Matador Resources Company Annual Report 2016

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FY2016 Annual Report · Matador Resources Company

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NYSE: MTDR

MEETING THE

CHALLENGES

2 0 1 6 A N N UA L R E P O R T

MATADOR

RESOURCES

Matador is an independent energy company engaged in the exploration, development, production and

acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale

and other unconventional plays. Its current operations are focused primarily on the oil and liquids-rich portion

of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas.

Matador also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley

plays in Northwest Louisiana and East Texas. Additionally, Matador conducts midstream operations primarily,

as of February 17, 2017, through its midstream joint venture, San Mateo Midstream, LLC, in support of its

exploration, development and production operations and provides natural gas processing, natural gas, oil and

salt water gathering services and salt water disposal services to third parties on a limited basis.

FINANCIAL AND

OPERATING HIGHLIGHTS

($ in millions)

2014

2015

2016

Operating Data
Oil and Natural Gas Revenues
% Oil in Revenues
Net Income (Loss)
Adjusted EBITDA(1)

Balance Sheet Data
Cash
Net Property and Equipment
Total Assets
Current Liabilities
Long-Term Liabilities
Total Shareholders’ Equity

Net Production Volumes
Oil (MBbl)
Natural Gas (Bcf)
Total Oil Equivalent (MBOE)(3),(4)
% Oil in Production Volumes(4)
Average Daily Production (BOE/d)(4)

Reserves Information
Total Proved Reserves (MMBOE)(4),(5)
% Oil in Proved Reserves(4)
Standardized Measure
PV-10(6)

$ 367.7

79%

$ 110.8
$ 262.9

$
8.4
$ 1,322.1
$ 1,434.5
$ 142.0
$ 425.9
$ 866.5

3,320
15.3
5,870

57%

16,082

68.7

35%

$ 913.3
$ 1,043.4

$ 278.3

73%

$
$

(679.8)
223.2

59.8(2)

$
$ 1,012.4
$ 1,140.9
136.8
$
$ 515.1
$ 489.0

4,492
27.7
9,109

49%

24,955

85.1

54%

$ 529.2
$ 541.6

$
$

291.2

72%

(97.4)
157.9

$
212.9
$ 1,184.5
$ 1,464.7
169.5
$
603.7
$
691.4
$

5,096
30.5
10,180

50%

27,813

105.8

54%
575.0
581.5

$
$

(1) Adjusted EBITDA is a non-GAAP ﬁnancial measure. For a deﬁnition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash

provided by operating activities, see “Selected Financial Data – Non-GAAP Financial Measures” in the Annual Report on Form 10-K enclosed herein.

(2) Including $43 million of restricted cash held in escrow at December 31, 2015.
(3) Thousands of barrels of oil equivalent.
(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(5) Millions of barrels of oil equivalent.
(6) PV-10 is a non-GAAP ﬁnancial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business — Estimated Proved Reserves” in the Annual Report on

Form 10-K enclosed herein.

AREAS OF

OPERATION

SOUTHEAST NEW MEXICO
AND WEST TEXAS

NORTHWEST LOUISIANA
AND EAST TEXAS

SOUTH TEXAS

NORTHWEST LOUISIANA
AND EAST TEXAS

Production: 5,300 BOE/d(1)

Proved Reserves: 13.1 MMBOE(2)

Acreage: 26,000 gross / 23,300 net(3)

Locations: 502 gross / 153 net(3)

SOUTH TEXAS

Production: 4,000 BOE/d(1)

Proved Reserves: 13.3 MMBOE(2)

Acreage: 30,700 gross / 27,800 net(3)

Locations: 249 gross / 214 net(3)

MATADOR RESOURCES COMPANY TOTALS

Production: 30,000 BOE/d(1)

Proved Reserves: 105.8 MMBOE(2)

Acreage: 234,300 gross / 152,500 net(3)

Locations: 4,985 gross / 2,151 net(3)

SOUTHEAST NEW MEXICO
AND WEST TEXAS

Production: 20,700 BOE/d(1)

Proved Reserves: 79.4 MMBOE(2)

Acreage: 177,600 gross / 101,400 net(3)

Locations: 4,234 gross / 1,784 net(3)

For the three months ended December 31, 2016.

(2) As of December 31, 2016.
(3) As of February 22, 2017.

DEAR SHAREHOLDERS
AND FRIENDS

Matador’s 2016 operating and ﬁnancial results were once

the Delaware Basin using state-of-the-art equipment and

again very pleasing, and I want to thank and commend the

technologies as well as innovative drilling, completion and

Board and the staff for such outstanding results in the face of

production practices. Well costs were reduced as much as 15

the most difficult and challenging commodity price environment

to 20% per well during the course of the year, while average

in recent memory. With everyone’s extraordinary efforts,

estimated ultimate recoveries increased 10 to 50% in certain

we were able to report record oil production of 5.1 million

of our asset areas as a result of applying these advanced

barrels and record natural gas production of 30.5 billion cubic

technologies and operating practices. The number of producing

feet, both of which were at the top of our 2016 guidance. The

horizons and potential new landing targets in our various asset

headlines for the year also included the fact that we increased

areas has grown signiﬁcantly since we went public. In fact, a

our proved oil and natural gas reserves by 24% year-over-year

number of our wells have achieved record results in both costs

to approximately 106 million BOE at December 31, 2016 and

and estimated recoveries and have considerably improved the

ﬁnished the year with over $200 million in cash in the bank and

commerciality of multiple producing horizons across our various

nothing borrowed on our line of credit. We have come a long way

acreage positions.

since we ﬁrst went public ﬁve years ago, as you can see from

the information contained in this Annual Report, and we like our

chances going forward!

In addition, Matador’s midstream business has signiﬁcantly

expanded the means by which we can add value to your shares.

Our midstream team added more gathering, processing and

This year, 2017, is already off to a strong start with the

disposal assets to our Delaware Basin property base in 2016,

announcement of another strategic midstream deal through

the highlight of which was successfully constructing and placing

a joint venture transaction with a high quality partner. The staff

into service our second cryogenic natural gas processing

also signiﬁcantly increased our leasehold and mineral acreage

plant in Eddy County, New Mexico, a plant that is twice the size

position to over 101,000 net acres in the Delaware Basin, which

of the Loving County plant we sold in 2015. Notably, Matador

is the most active and competitive oil and natural gas basin in

subsequently contributed 49% of the Eddy County plant and our

the country. The operations group has drilled headline grabbing

other Delaware Basin midstream assets into an exciting new

wells in each of our focus areas.

joint venture named San Mateo Midstream, LLC with an industry

Matador is also pleased to report that its operations and

geological groups continue to be technical leaders and

innovators in the understanding, delineation and drilling,

and completion and production of unconventional shales in

the Delaware Basin. As a result, we ﬁnished the year with

improvements to our acreage base, ﬁnancial strength and

staff capabilities. Details of these achievements and much

more information about Matador and our 2016 performance

are provided in the attached Annual Report on Form 10-K.

MEETING 2016 CHALLENGES

Virtually all of our operated drilling activity in 2016 focused

on the Delaware Basin in Southeast New Mexico and West

Texas. During this time, the Matador staff delivered impressive

improvements in drilling and completion efficiencies, associated

well costs and overall well results as we pursued the delineation

and development of our expanding acreage position throughout

partner in exchange for an upfront payment of $171.5 million

and future performance incentives that could result in total cash

payments of $245 million. By structuring the transaction as a

joint venture, your company has gained signiﬁcant operational

advantages, while retaining a 51% interest in this growing

Delaware Basin midstream business valued at approximately

$500 million at the time of the transaction. We plan to continue

expanding our midstream capabilities, and we look forward to

reporting on the future value created by this business.

MEETING NEXT YEAR’S CHALLENGES AND BEYOND

Substantially all of our anticipated 2017 capital investments

are again being directed toward our steadily improving and

growing oil and natural gas base in the Delaware Basin. These

ever-improving operations should further positively impact and

increase our production, proved reserves and per share value

this year. On many of Matador’s leases, the wells we drill in

2017 should also “prove up” other well locations on these same

leases — undrilled and undeveloped for now — but with the

and support of the shareholder group has helped us to meet

potential for millions of barrels of oil equivalent to be produced

the various challenges of the day. As we continue to grow as a

in years to come. Our Delaware Basin acreage position is being

public company, we strive to preserve the long-term outlook of

increasingly valued and appreciated across our industry. In

our company and desire for these relationships to continue to

short, Matador has in place a very exciting opportunity set

grow. Consequently, we invite each of you to attend our annual

for your Board and staff to ultimately develop into additional

shareholders’ meeting scheduled for 9:30 a.m. on June 1, 2017,

per share value.

In taking advantage of these opportunities, Matador will need

to meet whatever new challenges may emerge in 2017, such as

in Dallas, at the Westin Galleria Dallas Hotel, and to a continental

breakfast preceding the meeting beginning at 8:30 a.m. to meet

and visit with our staff and Board in person.

commodity price and market volatility, changes in government

Please accept this Annual Report and the accompanying proxy

policies and regulations, demand for vendor services, industry

materials as our special invitation to each of you to attend this

competition, and staff development and growth. In such an

meeting and to hear an update on our plans and progress on

environment, Matador must and will focus on execution and on

the opportunity set in front of us. It has been our great pleasure

those things we can control. As part of that effort, the Board, the

to serve you these many years as we meet the challenges

management team and I are all keeping an eye on maintaining

each year to build a great company with quality properties, a

the strength of the balance sheet and have challenged the

dedicated Board of Directors, a proven staff and a ﬁrst-class

staff to continue to deliver “better wells for less money.” We

investor group! We really enjoy seeing you at these meetings

are conﬁdent our proven management and technical staff will

and hope this year will again set another attendance record.

continue to work together creatively to meet these challenges

and to continue to add per share value to Matador in many

Very truly yours,

different ways, as they have done in the past.

Matador greatly appreciates and values the special relationships

we enjoy with our shareholders, our bondholders, our vendors

and other interested parties. We believe the long-term outlook

Joseph Wm. Foran
Chairman and Chief Executive Officer

NET DEBT / LTM ADJUSTED EBITDA(1),(2)

Net Debt
($ millions)

$101

$240

$256

$416

$359 $444

$362 $192

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2008

2009

2010

2011

1Q12

2Q12

3Q12

4Q12

1Q13

2Q13

3Q13

4Q13

1Q14

2Q14

3Q14

4Q14

1Q15

2Q15

3Q15

4Q15 1Q16

2Q16

3Q16 4Q16 4Q16
PF(3)

Note: Ratio is a measurement of leverage commonly used to quantify and analyze the ability of a company to repay its debts—the smaller the ratio, the better. The ratio
approximates the number of years required by a company to pay off its debts if the trailing twelve months Adjusted EBITDA were held constant and ignoring factors such as
interest, income taxes, depreciation, depletion, amortization, working capital adjustments and capital expenditures.
(1) Adjusted EBITDA is a non-GAAP ﬁnancial measure. For a deﬁnition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash

provided by operating activities, see our March 23, 2017 Analyst Day Presentation. LTM is last twelve months.

(2) Net Debt is equal to debt outstanding less available cash (including Matador’s proportionate share of any restricted cash).
(3) LTM Adjusted EBITDA and Net Debt at December 31, 2016 also shown pro forma for February 2017 San Mateo transaction and the purchase of the non-controlling interest

in Fulcrum Delaware Water Resources, LLC not previously owned by Matador.

(Seated, left to right) Reynald A. Baribault; Julia P. Forrester; Joseph Wm. Foran; Marlan W. Downey; George M. Yates
(Standing, left to right) James A. Rolfe; Kenneth L. Stewart; William M. Byerley; Gregory E. Mitchell; Dr. Steven W. Ohnimus; R. Gaines Baty; Joe A. Davis;
Craig T. Burkert; David M. Laney

BOARD OF DIRECTORS

Joseph Wm. Foran

Julia P. Forrester

Founder, Chairman and Chief Executive Officer of Matador Resources
Company (Matador II); Founder and Chief Executive Officer of Matador
Petroleum Corporation (Matador I)

Director; Associate Provost, Southern Methodist University; Professor of
Law, SMU Dedman School of Law; Former real estate attorney, Thompson
& Knight LLP

Reynald A. Baribault

David M. Laney

Lead Director; Vice President/Engineering and Co-Founder, NP Resources,
LLC; President and CEO, IPR Energy Partners, LLC; Former Vice President,
Netherland, Sewell & Associates, Inc.

R. Gaines Baty

Director; Chief Executive Officer, R. Gaines Baty Associates, Inc.

Craig T. Burkert

Director; Chief Financial Officer, ROMCO Equipment Co.

William M. Byerley

Director; Retired Partner (energy focus), PricewaterhouseCoopers (PwC)

Director; Past Chairman, Amtrak Board of Directors;
Former Partner, Jackson Walker LLP

Gregory E. Mitchell

Director; Chairman, Toot’n Totum Food Stores

Dr. Steven W. Ohnimus

Director; Retired Vice President and General Manager, Unocal Indonesia

Kenneth L. Stewart

Director; Partner, Chair – United States, Norton Rose Fulbright US LLP;
Former Global Chair of Fulbright & Jaworski LLP

Joe A. Davis

George M. Yates

Director; Retired Executive Vice President, General Counsel and Secretary,
EnLink Midstream, LLC and EnLink Midstream Partners, LP; Former
Partner, Hunton & Williams LLP

Director; Chairman and Chief Executive Officer, HEYCO Energy
Group, Inc.

SPECIAL BOARD ADVISORS

Ronney F. Coleman

Greg L. McMichael

Retired President – North America, Archer;
Former Vice President North America Pumping, BJ Services Co.;
Director, Goodrich Petroleum Corporation

Marlan W. Downey

Director Emeritus; Retired President, ARCO International;
Former President, Shell Pecten International;
Past President, American Association of Petroleum Geologists;
Sidney Powers Medalist from AAPG

Tara W. Lewis

Consultant, Director and Former Vice President, HEYCO Energy Group, Inc.;
Former Director of Internal Audit, Apache Corporation; Former Senior Tax
Manager, World Petroleum Group, PricewaterhouseCoopers (PwC)

Retired Vice President and Group Leader – Energy Research, A.G. Edwards, Inc.;
Director, Denbury Resources, Inc.

David F. Nicklin

Retired Executive Director of Exploration, Matador Resources Company;
Retired Chief Geologist, ARCO International

Dr. James D. Robertson

Retired Vice President, Exploration, Chief Geophysicist,
ARCO International

James A. Rolfe

Solo Practitioner;
Retired United States Attorney, Northern District of Texas

Wade I. Massad

Michael C. Ryan

Managing Member, Cleveland Capital Management, LLC;
Formerly with KeyBanc Capital Markets and RBC Capital Markets

Retired Partner, Berens Capital Management;
Former Director, Matador Resources Company

Surrounding Joe Foran, Matador’s Chairman and CEO (front, middle), are members of Matador’s staff. Matador had a total of 165 full-time
employees at December 31, 2016.

EXECUTIVE OFFICERS AND SENIOR MANAGEMENT

Joseph Wm. Foran

G. Gregg Krug

Founder, Chairman and Chief Executive Officer

Senior Vice President and Head of Marketing & Midstream

Matthew V. Hairford

Matthew D. Spicer

President and Chair of Operating Committee

Vice President and General Manager of Midstream

David E. Lancaster

Trent W. Green

Executive Vice President and Chief Financial Officer

Vice President – Production

Craig N. Adams

Robert T. Macalik

Executive Vice President – Land, Legal & Administration

Vice President and Chief Accounting Officer

Van H. Singleton, II

Executive Vice President – Land

Bradley M. Robinson

Senior Vice President of Reservoir Engineering
and Chief Technology Officer

Billy E. Goodwin

Senior Vice President of Operations

Kathryn L. Wayne

Vice President, Treasurer and Controller

Brian J. Willey

Vice President and Co-General Counsel

Bryan A. Erman

Vice President and Co-General Counsel

NYSE: MTDR

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
EXCHANGE COMMISSSIOIONN
UNITED STATES SECURITIES AND EXCHANGE COMMIS
Washington, D.C. 20549

FFORMORM 10-K10-K

(Mark One)
(cid:2)(cid:22)(cid:2)(cid:2) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the ﬁscal year ended December 31, 2016
or
(cid:2) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________________ to ________________

Commission ﬁle number: 001-34574

MATADOR RESOURCES COMPANY

(Exact name of registrant as speciﬁed in its charter)

Texas
(State or other jurisdiction of
incorporation or organization)

5400 LBJ Freeway, Suite 1500
Dallas, Texas 75240
(Address of principal executive ofﬁces)

27-4662601
(I.R.S. Employer
Identiﬁcation No.)

75240
(Zip Code)

Registrant’s telephone number, including area code: (972) 371-5200

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Common Stock, par value $0.01 per share

Name of each exchange on which registered

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as deﬁned in Rule 405 of the Securities Act. Yes (cid:2)(cid:22)(cid:2)(cid:2) No (cid:2)

Indicate by check mark if the registrant is not required to ﬁle reports pursuant to Section 13 or Section 15(d) of the Act. Yes (cid:2) No (cid:2)(cid:22)(cid:2)(cid:2)

Indicate by check mark whether the registrant (1) has ﬁled all reports required to be ﬁled by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to ﬁle such
reports), and (2) has been subject to such ﬁling requirements for the past 90 days. Yes (cid:2)(cid:22)(cid:2)(cid:2) No (cid:2)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such ﬁles). Yes (cid:2)(cid:22)(cid:2)(cid:2) No (cid:2)

Indicate by check mark if disclosure of delinquent ﬁlers pursuant to Item 405 of Regulation S-K is not contained herein, and will not
be contained, to the best of registrant’s knowledge, in deﬁnitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this Form 10-K. (cid:2)(cid:22)(cid:2)(cid:2)

Indicate by check mark whether the registrant is a large accelerated ﬁler, an accelerated ﬁler, a non-accelerated ﬁler, or a smaller
reporting company. See deﬁnitions of “large accelerated ﬁler,” “accelerated ﬁler” and “smaller reporting company” in Rule 12b-2
of the Exchange Act.
Large accelerated ﬁler (cid:2)(cid:22)(cid:2)(cid:2)
Non-accelerated ﬁler (cid:2) (Do not check if smaller reporting company)

Accelerated ﬁler
Smaller reporting company (cid:2)

(cid:2)

Indicate by check mark whether the registrant is a shell company (as deﬁned in Rule 12b-2 of the Exchange Act). Yes (cid:2) No (cid:2)(cid:22)(cid:2)(cid:2)

The aggregate market value of the voting and non-voting common equity of the registrant held by non-afﬁliates, computed by
reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently
completed second ﬁscal quarter was $1,625,286,901.

As of February 24, 2017, there were 100,034,559 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference
to the registrant’s deﬁnitive proxy statement relating to the 2017 Annual Meeting of Shareholders which will be ﬁled with the Securities
and Exchange Commission within 120 days after the end of the ﬁscal year to which this Annual Report on Form 10-K relates.

MATADOR RESOURCES COMPANY

Table of Contents

PART I

Item 1.

Item 1A.

Item 1B.

Item 2.

Item 3.

Item 4.

PART II

Item 5.

Item 6.

Item 7.

Item 7A.

Item 8.

Item 9.

Item 9A.

Item 9B.

PART III

Item 10.

Item 11.

Item 12.

Item 13.

Item 14.

PART IV

Item 15.

Page

Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases

of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

Management’s Discussion and Analysis of Financial Condition and Results Of Operations . . . . 73

Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure . . . . 99

Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

Directors, Executive Ofﬁcers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

Security Ownership of Certain Beneﬁcial Owners and Management and

Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . 102

Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103

FORM 10-K

2016 ANNUAL REPORT

Cautionary Note Regarding Forward-Looking Statements

Certain statements in this Annual Report on Form 10-K (this “Annual Report”) constitute “forward-looking
statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act,
and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Additionally,
forward-looking statements may be made orally or in press releases, conferences, reports, on our website or
otherwise, in the future by us or on our behalf. Such statements are generally identiﬁable by the terminology
used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,”
“intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should” or other similar words, although
not all forward-looking statements contain such identifying words.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that

may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties
and other factors that may cause actual results, levels of activity and achievements to differ materially from those
expressed or implied by such statements. Such factors include, among others: general economic conditions,
changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids,
the success of our drilling program, the timing of planned capital expenditures, the sufﬁciency of our cash ﬂow
from operations together with available borrowing capacity under our credit agreement, uncertainties in estimating
proved reserves and forecasting production results, operational factors affecting the commencement or
maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them,
the proximity to our properties and capacity of transportation facilities, availability of acquisitions, our ability to
integrate acquisitions with our business, weather and environmental conditions, uncertainties regarding environmental
regulations or litigation and other legal or regulatory developments affecting our business, and the other factors
discussed below and elsewhere in this Annual Report and in other documents that we ﬁle with or furnish to the
United States Securities and Exchange Commission, or the SEC, all of which are difﬁcult to predict. Forward-looking
statements may include statements about:

(cid:85) our business strategy;

(cid:85) our reserves;

(cid:85) our technology;

(cid:85) our cash ﬂows and liquidity;

(cid:85) our ﬁnancial strategy, budget, projections and operating results;

(cid:85) our oil and natural gas realized prices;

(cid:85)

the timing and amount of future production of oil and natural gas;

the availability of drilling and production equipment;

the availability of oil ﬁeld labor;

the amount, nature and timing of capital expenditures, including future exploration and development costs;

the availability and terms of capital;

(cid:85) our drilling of wells;

(cid:85) our ability to negotiate and consummate acquisition and divestiture opportunities;

(cid:85) government regulation and taxation of the oil and natural gas industry;

(cid:85) our marketing of oil and natural gas;

(cid:85) our exploitation projects or property acquisitions;

(cid:85)

the integration of acquisitions with our business;

FORM 10-K

MATADOR RESOURCES COMPANY

(cid:85) our ability and the ability of our midstream joint venture to construct and operate midstream facilities,
including the expansion of our Black River cryogenic natural gas processing plant and the drilling of
additional salt water disposal wells;

(cid:85) our costs of exploiting and developing our properties and conducting other operations;

(cid:85) general economic conditions;

(cid:85) competition in the oil and natural gas industry, including in both the exploration and production and

midstream segments;

(cid:85)

the effectiveness of our risk management and hedging activities;

(cid:85) environmental liabilities;

(cid:85) counterparty credit risk;

(cid:85) developments in oil-producing and natural gas-producing countries;

(cid:85) our future operating results;

(cid:85) estimated future reserves and the present value thereof; and

(cid:85) our plans, objectives, expectations and intentions contained in this Annual Report that are not historical.

Although we believe that the expectations conveyed by the forward-looking statements in this Annual Report
are reasonable based on information available to us on the date hereof, no assurances can be given as to future
results, levels of activity, achievements or ﬁnancial condition.

You should not place undue reliance on any forward-looking statement and should recognize that the statements

are predictions of future results, which may not occur as anticipated. Actual results could differ materially from
those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties
described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking
statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing
statements are not exclusive and further information concerning us, including factors that potentially could materially
affect our ﬁnancial results, may emerge from time to time. We do not intend to update forward-looking statements
to reﬂect actual results or changes in factors or assumptions affecting such forward-looking statements, except as
required by law, including the securities laws of the United States and the rules and regulations of the SEC.

FORM 10-K

2016 ANNUAL REPORT

Part I

ITEM 1. BUSINESS.

In this Annual Report, references to “we,” “our” or the “Company” refer to Matador Resources Company and

its subsidiaries as a whole (unless the context indicates otherwise) and references to “Matador” refer solely to
Matador Resources Company. For certain oil and natural gas terms used in this Annual Report, see the “Glossary
of Oil and Natural Gas Terms” included in this Annual Report.

GENERAL

We are an independent energy company engaged in the exploration, development, production and acquisition

of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other
unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp
and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the
Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and
East Texas. Additionally, we conduct midstream operations primarily, as of February 17, 2017, through our midstream
joint venture, San Mateo Midstream, LLC (“San Mateo” or the “Joint Venture”), in support of our exploration,
development and production operations and provide natural gas processing, natural gas, oil and salt water gathering
services and salt water disposal services to third parties on a limited basis.

We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began
his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in
contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador
Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive
Ofﬁcer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash
transaction for an enterprise value of approximately $388.5 million.

On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the
symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock.

Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash ﬂows
at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the
following business strategies:

(cid:85)

focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp
and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale
and Cotton Valley plays in Northwest Louisiana and East Texas;

identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced
portfolio of oil and natural gas properties;

(cid:85) continue to improve operational and cost efﬁciencies;

(cid:85)

identify and develop midstream opportunities that support and enhance our exploration and development
activities;

(cid:85) maintain our ﬁnancial discipline; and

(cid:85) pursue opportunistic acquisitions, divestitures and joint ventures.

Despite a challenging commodity price environment in 2016, the successful execution of our business strategies

led to signiﬁcant increases in our oil and natural gas production and proved oil and natural gas reserves. We also
signiﬁcantly increased our leasehold position in the Delaware Basin. In addition, we concluded several important
ﬁnancing transactions in 2016, including two equity offerings, an issuance of senior unsecured notes and an increase
in the borrowing base under our Credit Agreement (as deﬁned below). These transactions, as well as the formation
of the Joint Venture in February 2017, increased our operational ﬂexibility and further strengthened our balance sheet.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

2016 HIGHLIGHTS

Increased Oil, Natural Gas and Oil Equivalent Production

For the year ended December 31, 2016, we achieved record oil, natural gas and average daily oil equivalent
production. In 2016, we produced 5.1 million Bbl of oil, an increase of 13%, as compared to 4.5 million Bbl of oil
produced in 2015. We also produced 30.5 Bcf of natural gas, an increase of 10% from 27.7 Bcf of natural gas produced
in 2015. Our average daily oil equivalent production for the year ended December 31, 2016 was 27,813 BOE per
day, including 13,924 Bbl of oil per day and 83.3 MMcf of natural gas per day, an increase of 12%, as compared to
24,955 BOE per day, including 12,306 Bbl of oil per day and 75.9 MMcf of natural gas per day, for the year
ended December 31, 2015. The increase in oil and natural gas production was primarily a result of our ongoing
delineation and development operations in the Delaware Basin throughout 2016, which offset declining
production in the Eagle Ford and Haynesville shales where we have signiﬁcantly reduced our operated activity
since late 2014 and early 2015. Oil production comprised 50% of our total production (using a conversion ratio
of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2016, as compared to 49% for the
year ended December 31, 2015.

Increased Oil and Oil Equivalent Reserves

At December 31, 2016, our estimated total proved oil and natural gas reserves were 105.8 million BOE, including

57.0 million Bbl of oil and 292.6 Bcf of natural gas, an increase of 24% from December 31, 2015. The associated
Standardized Measure and PV-10 of our estimated total proved oil and natural gas reserves increased 9% and 7% to
$575.0 million and $581.5 million, respectively, at December 31, 2016, from $529.2 million and $541.6 million,
respectively, at December 31, 2015, primarily as a result of our ongoing delineation and development operations in
the Delaware Basin. PV-10 is a non-GAAP ﬁnancial measure. For a reconciliation of PV-10 to Standardized Measure,
see “—Estimated Proved Reserves.”

Our proved oil reserves grew 25% to 57.0 million Bbl at December 31, 2016 from 45.6 million Bbl at December 31,

2015. Our proved natural gas reserves increased 24% to 292.6 Bcf at December 31, 2016 from 236.9 Bcf at
December 31, 2015. This growth in oil and natural gas reserves was primarily attributable to our ongoing delineation
and development operations in the Delaware Basin during 2016.

At December 31, 2016, proved developed reserves included 22.6 million Bbl of oil and 126.8 Bcf of natural gas,
and proved undeveloped reserves included 34.4 million Bbl of oil and 165.9 Bcf of natural gas. Proved developed
reserves and proved oil reserves comprised 41% and 54%, respectively, of our total proved oil and natural gas reserves
at December 31, 2016. Proved developed reserves and proved oil reserves comprised 40% and 54%, respectively,
of our total proved oil and natural gas reserves at December 31, 2015.

Operational Highlights

We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per

well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical
approach to track and monitor the effectiveness of our drilling and completion techniques and service providers.
This allows us to better manage operating costs, the pace of development activities, technical applications, the
gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas,
which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors,
we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin
wells, particularly over the past three years, as we continue to apply what we learned from our Eagle Ford shale
and Haynesville shale experience. The Delaware Basin will continue to be our primary area of focus in 2017.

FORM 10-K PART I

2016 ANNUAL REPORT

We completed and began producing oil and natural gas from 55 gross (37.0 net) wells in the Delaware Basin
in 2016, including 40 gross (35.6 net) operated and 15 gross (1.4 net) non-operated wells. We also added to and
upgraded our acreage position in the Delaware Basin during 2016. As a result, at December 31, 2016, our total
acreage position in the Delaware Basin had increased to approximately 163,700 gross (94,300 net) acres, primarily
in Loving County, Texas and Lea and Eddy Counties, New Mexico. Overall, we have been very pleased with the
initial performance of the wells we have drilled and completed, or participated in as a non-operator, thus far in our
six main asset areas in the Delaware Basin—the Wolf and Jackson Trust asset areas in Loving County, Texas, the
Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Ranger and Twin Lakes asset areas
in Lea County, New Mexico. As a result, our Delaware Basin properties have become an increasingly important
component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased
approximately 145% (2.5-fold) to 15,941 BOE per day (57% of total oil equivalent production), including 10,395 Bbl
of oil per day (75% of total oil production) and 33.3 MMcf of natural gas per day (40% of total natural gas production),
in 2016, as compared to 6,518 BOE per day (26% of total oil equivalent production), including 4,648 Bbl of oil per
day (38% of total oil production) and 11.2 MMcf of natural gas per day (15% of total natural gas production), in 2015.
We expect our Delaware Basin production to increase throughout 2017 as we continue the delineation and
development of these asset areas.

Operational highlights in the Delaware Basin (as further described below in “—Principal Areas of Interest—

Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin” and “—Midstream
Segment”) in 2016 included:

(cid:85) our continued improvement in operational efﬁciencies throughout the Delaware Basin, particularly in our
Rustler Breaks and Wolf asset areas, as we achieved improvements in both drilling times and well costs;

(cid:85)

in our Rustler Breaks asset area, the continued delineation and development of previously tested horizons—
the Second Bone Spring, the Wolfcamp A-XY and two benches of the Wolfcamp B—and the successful
testing of a new, deeper bench of the Wolfcamp B interval, which is sometimes referred to as the Blair Shale;

in our Wolf asset area, continued development of the Wolfcamp A-XY interval as well as the signiﬁcant
improvement in well results in the Second Bone Spring, as compared to our initial tests in that interval;

in our Ranger asset area, the initial results from three wells completed in the Third Bone Spring formation
on our Mallon leasehold, which tested at the highest 24-hour initial potential ﬂow rates of any wells we
have drilled to date in the Delaware Basin and which illustrate the potential of our northern Delaware Basin
acreage position;

(cid:85) a positive test of the Strawn formation in our Twin Lakes asset area from the Olivine State 5-16S-37E TL #1,

a vertical well; and

(cid:85)

the signiﬁcant progress made with our midstream operations including the start-up of our Black River
cryogenic natural gas processing plant (the “Black River Processing Plant”) and associated natural gas
gathering system in our Rustler Breaks asset area, our initial salt water disposal well and facility and
associated water gathering lines in our Rustler Breaks asset area and two additional salt water disposal
wells and facilities in our Wolf asset area.

We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or

in Northwest Louisiana and East Texas during 2016, although we did participate in the drilling and completion of
2 gross (less than 0.1 net) non-operated Eagle Ford shale wells and 15 gross (2.1 net) non-operated Haynesville shale
wells that began producing in 2016.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Financing Arrangements

On March 11, 2016, we completed a public offering of 7,500,000 shares of our common stock. After deducting

offering costs totaling approximately $0.8 million, we received net proceeds of approximately $141.5 million. In
late October 2016, the lenders party to our third amended and restated credit agreement (the “Credit Agreement”),
under which we had no borrowings outstanding at December 31, 2016, increased our borrowing base from
$300.0 million to $400.0 million. On December 9, 2016, we issued $175.0 million of our 6.875% senior unsecured
notes due 2023 (the “Additional Notes”) in a private placement. We received net proceeds from the issuance of
Additional Notes of $181.5 million, including the issue premium, but after deducting the initial purchasers’ discounts
and estimated offering expenses and excluding accrued interest paid by buyers of the Additional Notes. Also on
December 9, 2016, we completed a public offering of 6,000,000 shares of our common stock. After deducting
offering costs totaling approximately $0.4 million, we received net proceeds of approximately $145.8 million. See
Notes 6 and 10 to the consolidated ﬁnancial statements in this Annual Report for more details on each of the
above items.

2017 RECENT DEVELOPMENTS

Between January 1, 2017 and February 22, 2017, we acquired approximately 13,900 gross (8,200 net) leasehold

and mineral acres and approximately 1,000 BOE per day of related production from various lessors and other
operators, mostly in and around our existing acreage in the Delaware Basin. Some of this acreage, and a portion
of the production, included properties identiﬁed at the time of our December 2016 equity and notes offerings.
These transactions were pending at the time of those offerings and closed subsequent to December 31, 2016,
bringing our total Permian Basin acreage position at February 22, 2017 to 177,600 gross (101,400 net) acres,
almost all of which was located in the Delaware Basin. We have incurred capital expenditures of approximately
$111 million since January 1, 2017 to acquire leasehold and mineral interests and the related production.

On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary

of Five Point Capital Partners LLC (“Five Point”). The midstream assets contributed to San Mateo include
(i) the Black River Processing Plant; (ii) one salt water disposal well and a related commercial salt water disposal
facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water
disposal facilities in the Wolf asset area; and (iv) substantially all related oil, natural gas and water gathering systems
and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”).
We received $171.5 million in connection with the formation of the Joint Venture and may earn up to an additional
$73.5 million in performance incentives over the next ﬁve years. We continue to operate the Delaware Midstream
Assets and retain operational control of the Joint Venture. The Company and Five Point own 51% and 49% of the
Joint Venture, respectively. San Mateo will continue to provide ﬁrm capacity service to us at market rates, while
also being a midstream service provider to third parties in and around our Wolf and Rustler Breaks asset areas.

PRINCIPAL AREAS OF INTEREST — EXPLORATION AND PRODUCTION SEGMENT

Our focus since inception has been the exploration for oil and natural gas in unconventional plays with an

emphasis in recent years on the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico
and West Texas, the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana
and East Texas. During 2016, we devoted most of our efforts and most of our capital expenditures to our drilling and
completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream
operations there. Since our inception, our exploration efforts have concentrated primarily on known hydrocarbon-
producing basins with well-established production histories offering the potential for multiple-zone completions.
We have also sought to balance the risk proﬁle of our asset areas by exploring for more conventional targets as well,
although at December 31, 2016, essentially all of our efforts were focused on unconventional plays.

FORM 10-K PART I

2016 ANNUAL REPORT

At December 31, 2016, our principal areas of interest consisted of the Wolfcamp and Bone Spring plays in the

Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale play in South Texas and the
Haynesville shale play, as well as the traditional Cotton Valley and Hosston (Travis Peak) formations, in Northwest
Louisiana and East Texas.

The following table presents certain summary data for each of our operating areas as of and for the year ended

December 31, 2016.

Southeast New Mexico/
West Texas:

Producing
Wells

Total Identiﬁed
Drilling Locations (1)

Gross
Acreage

Net
Acreage

Gross

Net

Gross

Net

Estimated Net
Proved Reserves (2)

Avg. Daily
Production
%
MBOE(3) Developed (BOE/d)(3)

Delaware Basin (4)

163,703

94,312

312

135.1

4,162

1,660.2

79,388

35.5

15,941

Eagle Ford (5)

30,669

27,777

136

115.1

249

214.2

13,298

55.0

4,952

East Texas:

Haynesville
Cotton Valley

VV
Area Total (7)
Total (8)

(6)

20,105
21,614
26,062
220,434

12,452
19,071
23,278
145,367

204
81
285
733

19.8
54.2
74.0
324.2

431
71
502
4,913

103.0
50.1
153.1
2,027.5

12,414
652
13,066
105,752

61.1
100.0
63.0
41.4

6,517
403
6,920
27,813

Identiﬁed and engineered drilling locations. These locations have been identiﬁed for potential future drilling and were not producing at
December 31, 2016. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating
area by our working interest participation in such locations. At December 31, 2016, these engineered drilling locations included only 163 gross
(90.3 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the
Delaware and Strawn formations in the Delaware Basin, 21 gross (21.0 net) locations to which we have assigned proved undeveloped reserves
in the Eagle Ford and 12 gross (4.0 net) locations to which we have assigned proved undeveloped reserves in the Haynesville.

(2) These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas
Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference.

(3) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4) Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Delaware, Strawn and Avalon plays on our acreage in the

Delaware Basin at December 31, 2016.

(5) Includes one well producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from

the San Miguel formation in Zavala County, Texas.

(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(7) Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore,
the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes
acreage that we are producing from or that we believe to be prospective for these formations.

(8) During the year ended December 31, 2016, we released all of our acreage in Wyoming, Utah and Idaho.

We are active both as an operator and as a co-working interest owner with larger industry participants, including

afﬁliates of EOG Resources, Inc., Royal Dutch Shell plc, Chesapeake Energy Corporation, EP Energy Company,
Concho Resources Inc., Devon Energy Corporation, Cimarex Energy Company, BHP Billiton, Mewbourne Oil Company,
Occidental Petroleum Corporation, Chevron Corporation and others. At December 31, 2016, we operated the
majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we
are not the operator, our working interests are often relatively small. At December 31, 2016, we also were the
operator for approximately 93% of our Eagle Ford acreage and approximately 65% of our Haynesville acreage, including
approximately 32% of our acreage in what we believe is the core area of the Haynesville play. A large portion of
our acreage in the core area of the Haynesville shale is operated by Chesapeake.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

While we do not always have direct access to our operating partners’ drilling plans with respect to future well

locations on non-operated properties, we do attempt to maintain ongoing communications with the technical
staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget
and our booking of any related proved undeveloped well locations and reserves. We review these locations
with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their
concurrence with our estimates of these drilling plans and our approach to booking these reserves.

Southeast New Mexico and West Texas — Delaware Basin

The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production
province with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in
many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir
targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and
hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich
shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the
Bone Spring, Avalon and Delaware formations. We believe these formations, which have been typically considered
low quality rocks because of their low permeability, are strong candidates for horizontal drilling and advanced
hydraulic fracturing techniques.

In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone
Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked
layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic
submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas
produced in the basin. Historically, production has come from conventional reservoirs; however, we and other
industry players have realized that the source rocks also have sufﬁcient porosity and permeability to be commercial
reservoirs. In addition, the source rocks are interbedded with reservoir layers that have ﬁlled with hydrocarbons,
both of which can produce signiﬁcant volumes of oil and natural gas when connected by horizontal wellbores with
multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a
given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring
and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identiﬁed and targeted by
companies, including us, throughout the vertical section including the Delaware, Avalon, Bone Spring (First, Second
and Third Sand) and several intervals within the Wolfcamp shale, often identiﬁed as Wolfcamp A through D.

As noted above in “—2016 Highlights—Operational Highlights,” we increased our acreage position in the

Delaware Basin during 2016, and as a result, at December 31, 2016, our total acreage position in Southeast
New Mexico and West Texas was approximately 163,700 gross (94,300 net) acres, primarily in Loving County, Texas
and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 32,700 gross (20,400 net)
acres in our Ranger asset area in Lea County, 48,000 gross (17,000 net) acres in our Arrowhead asset area in
Eddy County, 25,100 gross (16,500 net) acres in our Rustler Breaks asset area in Eddy County, 13,500 gross (8,400 net)
acres in our Wolf and Jackson Trust asset areas in Loving County and 42,900 gross (30,800 net) acres in our
Twin Lakes asset area in Lea County at December 31, 2016. We consider the vast majority of our Delaware Basin
acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations.
Other potential targets on certain portions of our acreage include the Avalon and Delaware formations, as well as
the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2016, our acreage position
in the Delaware Basin was approximately 36% held by existing production. Excluding the Twin Lakes asset area,
where we have drilled only one vertical Strawn well, our acreage position in the Delaware Basin was approximately
47% held by existing production at December 31, 2016.

FORM 10-K PART I

2016 ANNUAL REPORT

During the year ended December 31, 2016, we continued the delineation and development of our Delaware Basin
acreage. We completed and began producing oil and natural gas from 55 gross (37.0 net) wells in the Delaware Basin,
including 40 gross (35.6 net) operated wells and 15 gross (1.4 net) non-operated wells, throughout our various asset
areas. At December 31, 2016, we had tested a number of different producing horizons at various locations across
our acreage position, including the Brushy Canyon, Avalon, two benches of the Second Bone Spring, the Third Bone
Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the
Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D and the Strawn. Most of our delineation and
development efforts have been focused on multiple completion targets between the Second Bone Spring and the
Wolfcamp B.

As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production

increased signiﬁcantly in 2016. Our average daily oil equivalent production from the Delaware Basin increased
approximately 145% (2.5-fold) to 15,941 BOE per day (57% of total oil equivalent production), including 10,395 Bbl
of oil per day (75% of total oil production) and 33.3 MMcf of natural gas per day (40% of total natural gas production),
in 2016, as compared to 6,518 BOE per day (26% of total oil equivalent production), including 4,648 Bbl of oil per
day (38% of total oil production) and 11.2 MMcf of natural gas per day (15% of total natural gas production), in 2015.
In addition, our average daily oil equivalent production from the Delaware Basin also grew approximately 138%
(2.4-fold) from 8,720 BOE per day in the fourth quarter of 2015 to 20,670 BOE per day in the fourth quarter of 2016.

At December 31, 2016, approximately 75% of our estimated total proved oil and natural gas reserves, or

79.4 million BOE, was attributable to the Delaware Basin, including approximately 46.9 million Bbl of oil and 195.1 Bcf
of natural gas, a 68% increase, as compared to 47.1 million BOE for the year ended December 31, 2015. Our
Delaware Basin proved reserves at December 31, 2016 comprised approximately 82% of our proved oil reserves
and 67% of our proved natural gas reserves, as compared to approximately 69% of our proved oil reserves and
40% of our proved natural gas reserves at December 31, 2015.

At December 31, 2016, we had identiﬁed 4,162 gross (1,660.2 net) engineered locations for potential future

drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the
shallower Avalon and Delaware formations and the deeper Strawn formation. These locations include 2,546 gross
(1,478.1 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these
locations. These engineered locations have been identiﬁed on a property-by-property basis and take into account
criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated
recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities
observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion
costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria.
Our engineered well locations at December 31, 2016 do not yet include all portions of our acreage position and do
not include any horizontal locations in our Twin Lakes asset area in Lea County, New Mexico (other than our upcoming
horizontal test of the Wolfcamp D in 2017). Our identiﬁed well locations presume that these properties may be
developed on 80- to 160-acre well spacing, although we believe that denser well spacing may be possible and that
multiple intervals may be prospective at any one surface location. As we explore and develop our Delaware Basin
acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2016,
these potential future drilling locations included only 163 gross (90.3 net) locations in the Delaware Basin, primarily
in the Wolfcamp and Bone Spring plays, but also in the Delaware and Strawn formations, to which we have
assigned proved undeveloped reserves.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

At December 31, 2016 and February 22, 2017, we were operating four drilling rigs in the Delaware Basin—two in

the Rustler Breaks asset area, one in the Wolf/Jackson Trust asset areas and one in the Ranger/Arrowhead and
Twin Lakes asset areas. We intend to operate four rigs in these asset areas throughout the remainder of 2017, and
we expect to add a ﬁfth drilling rig in the Delaware Basin beginning early in the second quarter of 2017. Thereafter,
we expect to operate this ﬁfth drilling rig in the Rustler Breaks asset area throughout the remainder of 2017. We
are also participating in non-operated wells in the Delaware Basin as these opportunities arise. We have allocated
substantially all of our 2017 estimated capital expenditure budget to our drilling and completion program and
midstream operations in the Delaware Basin, with the exception of amounts allocated to limited operations in
the Eagle Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated
well opportunities.

Rustler Breaks Asset Area

We made signiﬁcant progress delineating, developing and testing our acreage position in the Rustler Breaks
asset area in 2016. The ten Wolfcamp A-XY wells and two Wolfcamp B (Middle) wells completed and placed on
production in the Rustler Breaks asset area in 2016 were consistent with or better than the best Wolfcamp
A-XY wells and Wolfcamp B (Middle) wells drilled by us in this asset area to date. The Paul 25-24S-28E RB #221H
well tested at the highest 24-hour initial potential ﬂow rate of any Wolfcamp A-XY well we have drilled at Rustler
Breaks—1,701 BOE per day (74% oil)—and early performance from this well indicates that it may be the best
Wolfcamp A-XY well drilled to date at Rustler Breaks. During 2016, we tested our ﬁrst ﬁve wells drilled in the deepest
bench of the Wolfcamp B (Blair) at Rustler Breaks. This is the third bench of the Wolfcamp B we have successfully
tested at Rustler Breaks. These three target benches of the Wolfcamp B occur starting approximately 300 feet
into the 1,000-foot thick Wolfcamp B interval at Rustler Breaks and are each about 200 to 250 feet apart vertically.

The 24-hour initial potential ﬂow rates from the ﬁve Wolfcamp B (Blair) wells we completed and placed on

production in 2016—the Dr. Scrivner Federal 01-24S-28E RB #228H, the Jimmy Kone 05-24S-28E RB #228H,
the Janie Conner 13-24S-28E RB #221H, the Anne Com 15-24S-28E RB #221H (Anne Com #221H) and the
Tiger 14-24S-28E RB #227H—were the ﬁve highest 24-hour test results we have reported in the Delaware Basin
to date (with the exception of the three Mallon wells discussed below) at 2,570 BOE per day, 2,438 BOE per
day, 2,384 BOE per day, 2,364 BOE per day and 1,812 BOE per day, respectively, at about 35% oil. These 24-hour
initial potential test results compare favorably to those from other wells completed in the Wolfcamp B (Middle),
the Tiger 14-24S-28E RB #224H and Janie Conner 13-24S-28E RB #224H wells, which had 24-hour initial potential
rates of 1,533 BOE per day (43% oil) and 1,703 BOE per day (59% oil), respectively. The initial oil volumes
from these lower Wolfcamp B (Blair) completions were reasonably comparable to or better than those in the
Wolfcamp B (Middle), while the initial natural gas volumes were higher. In some instances, the oil rates tested
on the lower Wolfcamp B (Blair) wells were close to those tested on the Wolfcamp A-XY wells.

In the Rustler Breaks asset area in 2016, we reduced our average drilling time from spud to total depth in the
Wolfcamp A-XY by approximately 31% and 16%, as compared to 2014 and 2015, respectively, and in the Wolfcamp B
by approximately 50% and 35%, respectively. Our fastest-drilled Wolfcamp A-XY well, the B. Banker 33-23S-28E
#226H well, was drilled in 12.5 days from spud to a total depth of 14,350 feet, a decrease of almost 50% from
the average drilling time in late 2014, and our fastest-drilled Wolfcamp B well, the Anne Com #221H, was drilled in
17.4 days from spud to a total depth of 15,364 feet, a decrease of 58% from the average drilling time in 2014.
These drilling times of 12.5 and 17.4 days were faster than our 2016 drilling objectives of 14 days for the Wolfcamp
A-XY and 18 days for the Wolfcamp B, respectively, from spud to total depth. We delivered faster drilling times
as a result of our increased knowledge of the geology and our experience with drilling in the Rustler Breaks asset
area, as well as improvements in drilling the curve between the vertical and horizontal portions of these wells and
continued applications of improved drill bit and bottomhole assembly technologies.

FORM 10-K PART I

2016 ANNUAL REPORT

Due in part to these improvements in drilling times, continued innovation by our technical staff and lower
oilﬁeld services costs, the costs associated with recent Wolfcamp A-XY and Wolfcamp B wells at Rustler Breaks
continued to decline throughout 2016. We were able to drill, complete and equip several wells in the Wolfcamp
A-XY for just under $5 million each and in the Wolfcamp B for approximately $5.7 million each in mid-to-late 2016.

All of the Wolfcamp A-XY wells completed and placed on production in the Rustler Breaks asset area in 2016
were stimulated using our Generation 3 Wolfcamp stimulation treatment design, consisting of approximately 40 Bbl
of fracturing ﬂuid and 3,000 pounds of primarily 30/50 white sand per completed lateral foot. Similarly, we pumped
this Generation 3 Wolfcamp stimulation treatment design in our Wolfcamp B (Blair) completions in the third and
fourth quarters of 2016. Prior to this, most of our Wolfcamp A and B completions in the Rustler Breaks asset area
used approximately 30 to 40 Bbl of fracturing ﬂuid and 2,000 pounds of primarily 30/50 white sand per completed
lateral foot. We also continued to pump diverting agents in most of our stimulation treatments in the Rustler Breaks
asset area during the third and fourth quarters of 2016.

Wolf and Jackson Trust Asset Areas

Operational efﬁciencies continued to improve in the Wolf asset area as well. In 2016, we reduced our average
drilling time from spud to total depth in the Wolfcamp A-X and A-Y by approximately 52% and 10% as compared to
2014 and 2015, respectively, and in the Second Bone Spring by approximately 42% as compared to our ﬁrst well
drilled in the Second Bone Spring in 2015. Our fastest-drilled Wolfcamp A well, the Dorothy White 82-TTT-B33
#203H well, was drilled in 17.3 days from spud to a total depth of 15,550 feet, a decrease of 61% from the 2014
average drilling time and faster than our 2016 Wolfcamp A drilling objective of 18 days from spud to total depth
in the Wolf asset area. The Barnett 90-TTT-B01 WF #124H (Barnett #124H) well, a Second Bone Spring test, was
drilled in approximately 11.5 days (11.2 days normalized to a 5,000-foot lateral length) from spud to total depth,
with drilling times being faster than our 2016 year-end drilling target of 13 days for Second Bone Spring wells. In the
Barnett #124H and subsequent Second Bone Spring wells drilled in 2016, our drilling engineers were also able
to eliminate a second intermediate casing string typically used when drilling the Second Bone Spring in this area.
Not only did eliminating this casing string save approximately $650,000 in well costs on each Second Bone Spring
well drilled in 2016, but it also provided for larger casing to be set through the lateral, thereby reducing hydraulic
horsepower costs during fracturing operations and enhancing the number of artiﬁcial lift options available in
the future. Total costs to drill, complete and equip Second Bone Spring wells in the Wolf asset area were just over
$4 million in mid-to-late 2016.

Well costs associated with recent Wolfcamp A-X and A-Y wells drilled and completed in the Wolf asset area also

continued to decline. Costs to drill, complete and equip Wolfcamp A wells ranged between $5 and $6 million,
with a number of these wells at or below $5.5 million in mid-to-late 2016. As in the Rustler Breaks asset area, we
attribute these cost savings to the innovation and use of new technologies by our drilling, completions and
production teams, as well as lower oilﬁeld services costs.

Our Second Bone Spring completions in 2016 represented signiﬁcant improvements over our initial Second Bone

Spring well drilled in the Wolf asset area in 2015. We attribute this improvement in well performance to the
increased stimulation treatments pumped in 2016. The 2016 wells were completed using approximately 40 Bbl of
fracturing ﬂuid and 2,000 pounds of primarily 20/40 sand per completed lateral foot, compared to our initial Second
Bone Spring completion in the Wolf asset area, which used only 20 Bbl of fracturing ﬂuid and about 1,300 pounds of
primarily 30/50 sand per completed lateral foot. In particular, we were pleased with the test results observed from
the Johnson 44-02S-B53 WF #121H well, which had the highest test rate achieved from any Second Bone Spring
well we have drilled to date of 1,167 BOE per day (58% oil).

We did not complete and place on production any new wells in our Jackson Trust asset area in 2016, although

we do have several wells planned in our Jackson Trust asset area for 2017.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Ranger and Arrowhead Asset Areas

In the Ranger asset area in Lea County, New Mexico, we completed and placed on production the Mallon 27
Federal Com #1H, #2H and #3H wells, each of which are 7,300-foot laterals drilled and completed in the Third Bone
Spring sand. These wells were the ﬁrst operated wells we have drilled on the acreage acquired in our 2015 merger
with Harvey E. Yates Company (“HEYCO” and, such merger, the “HEYCO Merger”). In aggregate, these three
wells ﬂowed 7,856 BOE per day (91% oil) in their 24-hour initial potential tests. Each well was completed with
a 29-stage fracture treatment, including approximately 40 Bbl of ﬂuid and 3,000 pounds of primarily 20/40 white
sand per completed lateral foot. At December 31, 2016, these were the largest fracture treatments we have
pumped in a Bone Spring completion. The Mallon wells were among the best wells we have drilled to date in the
Delaware Basin, and these wells illustrate the potential of our northern Delaware Basin acreage position.

We did not conduct any operated drilling and completion activities in our Arrowhead asset area during 2016,
although we did participate in one new, non-operated well on our Arrowhead acreage during the ﬁrst quarter of
2016. This well, the Yates Petroleum Corporation Baroque “BTQ” Federal Com #1H well, tested at ﬂow rates
averaging approximately 1,300 BOE per day (including approximately 1,100 Bbl of oil per day and 1.2 MMcf of natural
gas per day) beginning in late March 2016. This well is located in the eastern portion of our Arrowhead asset
area in Eddy County, New Mexico. We own a 9.5% working interest in this well, which provides yet another indication
of the prospectivity of our northern Delaware Basin acreage.

Twin Lakes Asset Area

In our Twin Lakes asset area in northern Lea County, New Mexico, we drilled an initial data collection well, the

Olivine State 5-16S-37E TL #1 (Olivine State #1), during the fourth quarter of 2015. This was a vertical pilot hole
drilled for the purpose of collecting whole core and a detailed suite of geophysical logs to assist us in determining
the landing target for our initial horizontal test of the Wolfcamp D interval at Twin Lakes. We collected about
400 feet of whole core throughout much of the Wolfcamp D interval, and our geoscience staff, along with third-party
vendors, have conducted detailed description and analysis of the core data and well logs. The Olivine State #1 was
drilled through the Wolfcamp D and into and through the Strawn formation below. The Strawn interval at about
11,500 feet is a complex carbonate formation that has previously produced signiﬁcant quantities of oil and natural
gas in the Twin Lakes area. Upon drilling through the Strawn interval, our geoscience staff analyzed the well logs taken
across the interval and determined that there was the potential for a Strawn test. As a result, the Olivine State #1
was perforated and completed in the Strawn interval with a small acid treatment during the ﬁrst quarter of 2016.
This well ﬂowed 691 BOE per day (84% oil) during a 24-hour initial potential test, consisting of 579 Bbl of oil per day
and 0.7 MMcf of natural gas per day, at a ﬂowing surface pressure of 350 psi on a 32/64 inch choke. Given the
positive results from this Strawn test, we elected to produce the Olivine State #1 rather than plug back, kick off and
drill a horizontal Wolfcamp D test from this vertical wellbore as originally anticipated. We expect to drill a new
horizontal well to test the Wolfcamp D interval beginning late in the ﬁrst quarter of 2017.

South Texas — Eagle Ford Shale and Other Formations

The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a

band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and
lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the
Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few,
modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with
the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore
more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone.
The transition between being more oil prone and more natural gas prone includes an interval that typically
produces liquids-rich natural gas with condensate.

FORM 10-K PART I

2016 ANNUAL REPORT

At December 31, 2016, our properties included approximately 30,700 gross (27,800 net) acres in the Eagle Ford

shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe
that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with
condensate. Approximately 85% of our Eagle Ford acreage was held by production at December 31, 2016, and
approximately 95% of our Eagle Ford acreage was either held by production at December 31, 2016 or not burdened
by lease expirations before 2018.

We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas
during the year ended December 31, 2016, although we did participate in the drilling and completion of two gross
(less than 0.1 net) non-operated Eagle Ford shale wells that were turned to sales in 2016. In fact, as of December 31,
2016, we had not drilled any operated wells in the Eagle Ford shale since early 2015, when we completed and
placed on production 17 gross (17.0 net) operated Eagle Ford shale wells in the ﬁrst four months of 2015. As a result,
our average daily oil equivalent production from the Eagle Ford shale decreased 52% to 4,952 BOE per day,
including 3,517 Bbl of oil per day and 8.6 MMcf of natural gas per day, during 2016, as compared to 10,263 BOE per
day, including 7,642 Bbl of oil per day and 15.7 MMcf of natural gas per day, during 2015. For the year ended
December 31, 2016, 18% of our total daily oil equivalent production was attributable to the Eagle Ford shale. During
the year ended December 31, 2015, approximately 41% of our total daily oil equivalent production was attributable
to the Eagle Ford shale.

At December 31, 2016, approximately 13% of our estimated total proved oil and natural gas reserves, or
13.3 million BOE, was attributable to the Eagle Ford shale, including approximately 10.1 million Bbl of oil and
19.3 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 18% of our proved oil
reserves and 7% of our proved natural gas reserves at December 31, 2016, as compared to approximately 31% of
our proved oil reserves and 12% of our proved natural gas reserves at December 31, 2015.

At December 31, 2016, we had identiﬁed 249 gross (214.2 net) engineered locations for potential future drilling

on our Eagle Ford acreage. These locations have been identiﬁed on a property-by-property basis and take into
account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated
recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling
densities anticipated on our properties and observed on properties of other operators, estimated horizontal lateral
lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and
surface considerations, among other factors. The identiﬁed well locations presume that we will be able to develop
our Eagle Ford properties on 40- to 80-acre spacing, depending on the speciﬁc property and the wells we have
already drilled. We anticipate that any Eagle Ford wells drilled on our acreage in central and northern La Salle, northern
Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties,
particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing.
Approximately 95% of our Eagle Ford acreage was either held by production or not burdened by lease expirations
before 2018 at December 31, 2016. At December 31, 2016, these 249 gross (214.2 net) identiﬁed drilling locations
included only 21 gross (21.0 net) locations to which we have assigned proved undeveloped reserves.

These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale.
We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of
the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would
expect to produce predominantly oil and liquids. In addition, we believe portions of our Eagle Ford acreage may also
be prospective for the Austin Chalk, Buda and Edwards formations, from which we would expect to produce
predominantly oil and liquids. In particular, we own approximately 8,900 gross (8,900 net) contiguous acres on our
Glasscock Ranch property in southeast Zavala County, Texas, which are held by production and which we believe
may be prospective for the Buda formation. At December 31, 2016, we had not included any future drilling locations
in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale
or in the Austin Chalk or Buda formations.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Northwest Louisiana and East Texas

We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest

Louisiana and East Texas during 2016, although we did participate in the drilling and completion of 15 gross (2.1 net)
non-operated Haynesville shale wells that were turned to sales in 2016. These wells included nine gross (1.9 net)
Haynesville wells operated by a subsidiary of Chesapeake Energy Corporation (“Chesapeake”) on our Elm Grove
acreage in southern Caddo Parish, Louisiana. These nine wells came on production at an average of 13.5 MMcf per
day and were drilled and completed for an average of under $7 million. We do not plan to drill any operated
Haynesville shale wells in 2017.

At December 31, 2016, we held approximately 26,100 gross (23,300 net) acres in Northwest Louisiana and

East Texas, including 20,100 gross (12,500 net) acres in the Haynesville shale play. We operate all of our Cotton Valley
and shallower production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our
Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play.
We operate approximately 32% of the 13,200 gross (6,400 net) acres that we consider to be in the core area of the
Haynesville play.

For the year ended December 31, 2016, approximately 25% of our average daily oil equivalent production, or
6,920 BOE per day, including 12 Bbl of oil per day and 41.4 MMcf of natural gas per day, was attributable to our
leasehold interests in Northwest Louisiana and East Texas. Natural gas production from these properties comprised
approximately 50% of our daily natural gas production, but oil production from these properties comprised only about
0.1% of our daily oil production during 2016, as compared to approximately 64% of our daily natural gas production
and approximately 0.1% of our daily oil production during 2015. During the year ended December 31, 2015,
approximately 33% of our average daily oil equivalent production, or 8,174 BOE per day, including 16 Bbl of oil per
day and 48.9 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas.

For the year ended December 31, 2016, approximately 47% of our daily natural gas production, or 39.1 MMcf
of natural gas per day, was produced from the Haynesville shale, with approximately 3%, or 2.3 MMcf of natural gas
per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended
December 31, 2015, approximately 61% of our daily natural gas production, or 46.4 MMcf of natural gas per day, was
produced from the Haynesville shale, with approximately 3%, or 2.6 MMcf of natural gas per day, produced from
the Cotton Valley and other shallower formations on these properties. At December 31, 2016, approximately 12%
of our estimated total proved reserves, or 12.4 million BOE, was attributable to the Haynesville shale with another
1% of our proved reserves, or 0.7 million BOE, attributable to the Cotton Valley and shallower formations underlying
this acreage.

At December 31, 2016, we had identiﬁed and engineered 431 gross (103.0 net) locations for potential future
drilling in the Haynesville shale play and 71 gross (50.1 net) locations for potential future drilling in the Cotton Valley
formation. These engineered locations have been identiﬁed on a property-by-property basis and take into account
criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries
from our producing Haynesville and Cotton Valley wells and other nearby wells based on available public data,
drilling densities observed on properties of other operators, including on some of our non-operated properties,
estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by
regulatory authorities and surface conditions, among other criteria. Of the 431 gross (103.0 net) locations identiﬁed
for future drilling on our Haynesville acreage, 357 gross (50.1 net) locations have been identiﬁed within the 13,200
gross (6,400 net) acres that we believe are located in the core area of the Haynesville play. As we explore and
develop our Northwest Louisiana and East Texas acreage further, we believe it is possible that we may identify
additional locations for future drilling. At December 31, 2016, these potential future drilling locations included
only 12 gross (4.0 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have
assigned proved undeveloped reserves.

FORM 10-K PART I

2016 ANNUAL REPORT

Haynesville and Middle Bossier Shales

The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier

formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad
region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River
Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces
primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided
into lower, middle and upper units. The Middle Bossier shale appears to be productive for natural gas under large
portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas,
where it shares many similar productive characteristics with the deeper Haynesville shale. Although there is some
overlap between the Haynesville and Bossier shale plays, the two plays appear quite distinct and a separate
horizontal wellbore is typically needed for each formation.

At December 31, 2016, we had approximately 20,100 gross (12,500 net) acres in the Haynesville shale play,
primarily in Northwest Louisiana. Based on our analysis of geologic and petrophysical information (including total
organic carbon content and maturity, resistivity, porosity and permeability, among other information), well
performance data, information available to us related to drilling activity and results from wells drilled across the
Haynesville shale play, approximately 13,200 gross (6,400 net) acres are located in what we believe is the core area
of the play. We believe the core area of the play includes that area in which the most Haynesville wells have been
drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Almost
all of our Haynesville acreage is held by production or consists of fee mineral interests that we own and portions
of it are also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other
shallower formations. In addition, we believe that approximately 1,200 net acres are prospective for the Middle
Bossier shale play. We have never drilled a Middle Bossier shale well, and, although we believe that prospective
well locations may exist on this acreage, we have not included any Middle Bossier locations in our engineered
drilling locations at December 31, 2016.

Within the acreage that we believe to be in the core area of the Haynesville shale play, we are the operator of
approximately 2,100 net acres. We have identiﬁed 25 gross (19.6 net) potential additional Haynesville locations that
we may drill and operate in the future on this acreage. The remainder of our acreage in the core area of the
Haynesville shale play is operated by other companies, including our Elm Grove properties in southern Caddo Parish,
Louisiana that are operated by Chesapeake following a sale of a portion of our interests there in July 2008. The
working interests in our non-operated Haynesville wells are typically small, ranging from less than 1% to just over 31%.

Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations

Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and

reserves in Northwest Louisiana and East Texas was attributable to wells producing from the Cotton Valley
formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface
under our acreage in Northwest Louisiana and East Texas.

All of the shallow rights underlying our acreage in our Elm Grove properties in Northwest Louisiana, approximately

10,000 gross (9,800 net) acres at December 31, 2016, are held by existing production from the Cotton Valley
formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove
ﬁeld prior to discovery of the Haynesville shale. The Cotton Valley formation is a low permeability natural gas sand
that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

We have identiﬁed 71 gross (50.1 net) additional drilling locations for future Cotton Valley horizontal wells on our
Elm Grove properties. We did not drill any of these locations in 2016 and do not plan to drill any of these locations in
2017. As long as this leasehold acreage is held by existing production from the vertical Cotton Valley wells or the
deeper Haynesville shale wells, however, these Cotton Valley natural gas volumes remain available to be developed
by us should natural gas prices improve, drilling and completion costs decline or new technologies be developed
that increase expected recoveries.

We also continue to hold the shallow rights primarily by existing production on our Central and Southwest Pine
Island, Longwood, Woodlawn and other asset areas in Northwest Louisiana and East Texas. At December 31, 2016,
we held an estimated 11,600 gross (9,200 net) leasehold and mineral acres by existing production in these areas.

Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale

During the year ended December 31, 2016, we released all of our leasehold interests in Southwest Wyoming
and adjacent areas in Utah and Idaho, which were originally leased as a part of a natural gas shale exploration prospect
targeting the Meade Peak shale. As a result, we held no leasehold interests in these areas at December 31, 2016.

MIDSTREAM SEGMENT

The midstream segment conducts midstream operations in support of our exploration, development and

production operations and provides natural gas processing, natural gas, oil and salt water gathering services and salt
water disposal services to third parties on a limited basis. Through the ownership and operation of these facilities,
we improve our ability to manage costs and control the timing of bringing on new production, and we enhance the
value received for our production. With the exception of a joint venture, which we controlled and which owned
salt water disposal assets in Loving County, Texas, all of our midstream operations were wholly-owned by the
Company at December 31, 2016. In February 2017, we contributed our Delaware Midstream Assets to San Mateo.

Southeast New Mexico and West Texas — Delaware Basin

In late August 2016, we successfully completed and began operating the Black River Processing Plant in our
Rustler Breaks asset area in Eddy County, New Mexico. The Black River Processing Plant has an inlet capacity of
approximately 60 MMcf of natural gas per day, which is almost twice the size of the previous cryogenic processing
plant we built in our Wolf asset area in Loving County, Texas (the “Wolf Processing Plant”) and subsequently
sold to an afﬁliate of EnLink Midstream Partners, LP (“EnLink”) in October 2015. The Black River Processing Plant
and associated gathering system was built to support our ongoing and future development efforts in the Rustler
Breaks asset area and to provide us with priority one takeaway and processing services for our Rustler Breaks
natural gas production. It may also provide additional income through the gathering and processing of third-party
natural gas. We had previously completed the installation and testing of a 12-inch natural gas trunk line and
associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural
gas gathering lines are being used to gather almost all of our natural gas production at Rustler Breaks. In addition,
in late December 2016, we placed in service our initial salt water disposal well and associated salt water disposal
facility and water gathering pipelines in our Rustler Breaks asset area. We disposed of over 800,000 Bbl of salt
water during the well’s ﬁrst two months of operation.

FORM 10-K PART I

2016 ANNUAL REPORT

In our Wolf asset area in Loving County, Texas, we have oil, natural gas and salt water gathering systems that

gather our oil, natural gas and water production and a small volume of third-party natural gas. We retained this
three-pipeline system following the sale of our wholly-owned subsidiary that owned certain natural gas gathering
and processing assets in the Wolf asset area (the “Loving County Processing System”) to EnLink in October 2015.
The Loving County Processing System included the Wolf Processing Plant and approximately six miles of high-
pressure gathering pipeline that connects our gathering system to the Wolf Processing Plant. We also retained our
interest in commercial salt water disposal assets in Loving County. During 2016, we disposed of approximately
10.2 million Bbl of salt water, including disposal of third-party salt water on a commercial basis. At February 22, 2017,
San Mateo had capacity to dispose of approximately 50,000 Bbl of salt water per day in the Wolf asset area.
San Mateo is in the process of completing its third salt water disposal well and related disposal facility in the Wolf
asset area, which is expected to be operational by the end of the ﬁrst quarter of 2017 and which should increase
the total salt water disposal capacity in the Wolf asset area to approximately 75,000 Bbl per day.

South Texas / Northwest Louisiana and East Texas

In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our

operated Eagle Ford leases. In Northwest Louisiana and East Texas, we have midstream assets that gather and
treat natural gas from most of our operated leases there and from third parties. We also have four non-commercial
salt water disposal wells that dispose of our salt water. Our midstream assets in South Texas and Northwest
Louisiana and East Texas are not part of San Mateo.

OPERATING SUMMARY

The following table sets forth certain unaudited production and operating data for the years ended December 31,

2016, 2015 and 2014.

Unaudited Production Data:
Net Production Volumes:

Oil (MBbl)
Natural gas (Bcf)

Total oil equivalent (MBOE) (1)

Average daily production (BOE/d) (1)

Average Sales Prices:

Oil, without realized derivatives (per Bbl)
Oil, with realized derivatives (per Bbl)
Natural gas, without realized derivatives (per Mcf)
Natural gas, with realized derivatives (per Mcf)

Operating Expenses (per BOE):

Production taxes, transportation and processing
Lease operating
Plant and other midstream services operating
Depletion, depreciation and amortization
General and administrative

Year Ended December 31,

2016

2015

2014

5,096
30.5
10,180
27,813

$ 41.19
$ 42.34
$ 2.66
$ 2.78

$ 4.23
$ 5.52
$ 0.53
$ 11.99
$ 5.41

4,492
27.7
9,109
24,955

$ 45.27
$ 59.13
2.71
$
3.24
$

$ 3.91(2)
$ 6.01(3)
$
0.38
$ 19.63
5.50
$

3,320
15.3
5,870
16,082

$ 87.37
$ 88.94
$ 5.08
$ 5.06

$ 5.65
$ 8.51(3)
$ 0.24
$ 22.95
$ 5.48

(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(2) $0.01 per BOE reclassiﬁed to third-party midstream services revenues due to our midstream business becoming a reportable segment in the

third quarter of 2016.

(3) $0.38 and $0.24 per BOE reclassiﬁed to plant and other midstream services operating expenses for the years ended December 31, 2015 and

2014, respectively, due to our midstream business becoming a reportable segment in the third quarter of 2016.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

The following table sets forth information regarding our production volumes, sales prices and production
costs for the year ended December 31, 2016 from our operating areas, which we consider to be distinct ﬁelds for
purposes of accounting for production.

Southeast
New Mexico/
West Texas

South Texas

Northwest Louisiana/East Texas

Delaware Basin Eagle Ford (1)

Haynesville Cotton Valley

(2)

Total

3,805
12.2
5,834
57.3%

1,286
3.1
1,813
17.8%

—
14.3
2,385
23.4%

5
0.9
148
1.5%

5,096
30.5
10,180
100.0%

10,395
33.3
15,941

$ 41.76
$ 3.15
$ 33.81

3,517
8.6
4,952

$ 39.49
$ 3.11
$ 33.46

—
39.1
6,517

12
2.3
403

13,924
83.3
27,813

$ —
$ 2.17
$ 13.04

$ 38.78
$ 2.27
$ 14.39

$ 41.19
$ 2.66
$ 28.60

Production Costs (5)
Lease operating, transportation and processing (per BOE)

$ 7.32

$ 12.74

$ 4.73

$ 17.07

$ 7.82

Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from
the San Miguel formation in Zavala County, Texas.

(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(3) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4) Excludes impact of derivative settlements.

(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.

FORM 10-K PART I

2016 ANNUAL REPORT

The following table sets forth information regarding our production volumes, sales prices and production costs
for the year ended December 31, 2015 from our operating areas, which we consider to be distinct ﬁelds for purposes
of accounting for production.

Southeast
New Mexico/
West Texas

South Texas

Northwest Louisiana/East Texas

Delaware Basin Eagle Ford (1)

Haynesville Cotton Valley

(2)

Total

1,697
4.1
2,379

Annual Net Production Volumes
Oil (MBbl)
Natural gas (Bcf)
Total oil equivalent (MBOE) (3)
Percentage of total annual net production
Average Net Daily Production Volumes
Oil (Bbl/d)
Natural gas (MMcf/d)
Total oil equivalent (BOE/d)
Average Sales Prices (4)
Oil (per Bbl)
Natural gas (per Mcf)
Total oil equivalent (per BOE)
Production Costs (5)
Lease operating, transportation and processing (per BOE) (6) $ 8.84

$ 43.54
$ 3.00
$ 36.21

4,648
11.2
6,518

26.1%

2,789
5.7
3,746

—
16.9
2,822

41.1%

31.0%

6
1.0
162
1.8%

4,492
27.7
9,109
100.0%

7,642
15.7
10,263

$ 46.33
$ 3.17
$ 39.35

—
46.4
7,731

16
2.6
443

$ —
$ 2.49
$14.97

$43.68
$ 2.45
$15.69

12,306
75.9
24,955

$ 45.27
$
2.71
$ 30.56

$ 9.25

$ 4.91

$19.23

7.90

(1)

Includes one wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from
the San Miguel formation in Zavala County, Texas.

(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(3) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4) Excludes impact of derivative settlements.

(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.

(6) Amounts have been adjusted to reﬂect the reclassiﬁcation of certain lease operating expenses to plant and other midstream services operating

expenses due to our midstream business becoming a reportable segment in the third quarter of 2016.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

The following table sets forth information regarding our production volumes, sales prices and production costs
for the year ended December 31, 2014 from our operating areas, which we consider to be distinct ﬁelds for purposes
of accounting for production.

Southeast
New Mexico/
West Texas

South Texas

Northwest Louisiana/East Texas

Delaware Basin Eagle Ford (1)

Haynesville Cotton Valley

(2)

480
1.0
653
11.1%

2,834
6.0
3,833

—
7.2
1,201

65.3%

20.5%

1,314
2.9
1,790

$ 80.16
$ 4.75
$ 66.41

7,764
16.4
10,501

$ 88.58
$ 6.72
$ 75.99

—
19.7
3,290

$ —
$ 3.87
$23.27

$91.24
$ 4.30
$27.92

6
1.1
183
3.1%

17
2.9
501

Total

3,320
15.3
5,870
100.0%

9,095
41.9
16,082

$ 87.37
$
5.08
$ 62.64

$ 13.08

$ 10.34

$ 8.13

$17.58

$ 10.29

(1)

Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from
the San Miguel formation in Zavala County, Texas.

(2) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

(3) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4) Excludes impact of derivative settlements.

(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.

(6) Amounts have been adjusted to reﬂect the reclassiﬁcation of certain lease operating expenses to plant and other midstream services operating

expenses due to our midstream business becoming a reportable segment in the third quarter of 2016.

Our total oil equivalent production of approximately 10.2 million BOE for the year ended December 31, 2016

increased 12% from our total oil equivalent production of approximately 9.1 million BOE for the year ended
December 31, 2015. This increased production was primarily due to our delineation and development operations in
the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales where we have
not drilled any new operated wells since the second quarter of 2015. Our average daily oil equivalent production for
the year ended December 31, 2016 was 27,813 BOE per day, as compared to 24,955 BOE per day for the year
ended December 31, 2015. Our average daily oil production for the year ended December 31, 2016 was 13,924 Bbl
of oil per day, an increase of 13% from 12,306 Bbl of oil per day for the year ended December 31, 2015. Our
average daily natural gas production for the year ended December 31, 2016 was 83.3 MMcf of natural gas per day,
an increase of 10% from 75.9 MMcf of natural gas per day for the year ended December 31, 2015.

Our total oil equivalent production of approximately 9.1 million BOE for the year ended December 31, 2015

increased 55% from our total oil equivalent production of approximately 5.9 million BOE for the year ended
December 31, 2014. This increased production was primarily due to our delineation and development operations in
the Delaware Basin and new, non-operated Haynesville shale wells completed and placed on production on our
Elm Grove properties in Northwest Louisiana during the latter half of 2014 and into 2015, as well as from newly
drilled and completed wells in the Eagle Ford shale in early 2015. Our average daily oil equivalent production for the
year ended December 31, 2015 was 24,955 BOE per day, as compared to 16,082 BOE per day for the year ended
December 31, 2014. Our average daily oil production for the year ended December 31, 2015 was 12,306 Bbl of
oil per day, an increase of 35% from 9,095 Bbl of oil per day for the year ended December 31, 2014. Our average
daily natural gas production for the year ended December 31, 2015 was 75.9 MMcf of natural gas per day, an
increase of 81% from 41.9 MMcf of natural gas per day for the year ended December 31, 2014.

FORM 10-K PART I

2016 ANNUAL REPORT

PRODUCING WELLS

The following table sets forth information relating to producing wells at December 31, 2016. Wells are classiﬁed
as oil wells or natural gas wells according to their predominant production stream. We had an approximate average
working interest of 72% in all wells that we operated at December 31, 2016. For wells where we are not the
operator, our working interests range from less than 1% to as much as just over 50%, and average approximately
10%. In the table below, gross wells are the total number of producing wells in which we own a working interest
and net wells represent the total of our fractional working interests owned in the gross wells.

Southeast New Mexico/West Texas:

Delaware Basin (1)

South Texas:

Eagle Ford (2)

Northwest Louisiana/East Texas:

Haynesville
Cotton Valley
VV
Area Total
Total

(3)

Oil Wells

Natural Gas Wells

Total Wells

Gross

Net

Gross

Net

Gross

Net

261

116.0

19.1

312

135.1

132

111.1

4.0

136

115.1

—
2
2
395

—
2.0
2.0
229.1

204
79
283
338

19.8
52.2
72.0
95.1

204
81
285
733

19.8
54.2
74.0
324.2

(1)

Includes 176 gross (50.5 net) wells acquired in February 2015 as part of the HEYCO Merger.

(2) Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from

the San Miguel formation in Zavala County, Texas.

(3) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

ESTIMATED PROVED RESERVES

The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2016, 2015 and

2014. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and
liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford
shale, the economic value of the natural gas liquids associated with the natural gas is included in the estimated
wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. The reserves
estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness
by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were
prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown
are for proved reserves only and do not include any unproved reserves classiﬁed as probable or possible reserves
that might exist for our properties, nor do they include any consideration that could be attributable to interests in
unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil
and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Estimated Proved Reserves Data:(2)
Estimated proved reserves:

Oil (MBbl)
Natural Gas (Bcf) (3)
Total (MBOE) (4)

Estimated proved developed reserves:

Oil (MBbl)
Natural Gas (Bcf) (3)
Total (MBOE) (4)

Percent developed

Estimated proved undeveloped reserves:

Oil (MBbl)
Natural Gas (Bcf) (3)
Total (MBOE) (4)

Standardized Measure (5) (in millions)
PV-10VV

(6) (in millions)

(1) Numbers in table may not total due to rounding.

At December 31,(1)

2016

2015

2014

56,977
292.6
105,752

22,604
126.8
43,731

45,644
236.9
85,127

17,129
101.4
34,037

24,184
267.1
68,693

14,053
102.8
31,185

41.4%

40.0%

45.4%

34,373
165.9
62,021

28,515
135.5
51,090

10,131
164.3
37,508

$ 575.0
$ 581.5

$ 529.2
$ 541.6

$ 913.3
$1,043.4

(2) Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving
effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the
ﬁrst-day-of-the-month prices for the 12 months ended December 31, 2016 were $39.25 per Bbl for oil and $2.48 per MMBtu for natural gas, for
the 12 months ended December 31, 2015 were $46.79 per Bbl for oil and $2.59 per MMBtu for natural gas, and for the 12 months ended
December 31, 2014 were $91.48 per Bbl for oil and $4.35 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy
content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead.
We report our proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural
gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold.

(3) Primarily as a result of substantially lower natural gas prices in 2015, we removed approximately 64.3 Bcf (10.7 million BOE) of previously

classiﬁed proved undeveloped natural gas reserves from our total proved reserves in 2015, most of which were attributable to non-operated
properties in the Haynesville shale.

(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. Primarily as a result of the lower weighted average oil and natural
gas prices used to estimate proved oil and natural gas reserves in 2016, we removed approximately 11.6 million BOE of previously classiﬁed
proved undeveloped reserves from our total proved reserves in 2016.

(5) Standardized Measure represents the present value of estimated future net cash ﬂows from proved reserves, less estimated future

development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reﬂect the timing of
future cash ﬂows. Standardized Measure is not an estimate of the fair market value of our properties.

(6) PV-10 is a non-GAAP ﬁnancial measure and generally differs from Standardized Measure, the most directly comparable GAAP ﬁnancial

measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of
our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by
companies and of the potential return on investment related to the companies’ properties without regard to the speciﬁc tax characteristics of
such entities. Our PV-10 at December 31, 2016, 2015 and 2014 may be reconciled to our Standardized Measure of discounted future net
cash ﬂows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future
income taxes at December 31, 2016, 2015 and 2014 were, in millions, $6.5, $12.4 and $130.1, respectively.

Our estimated total proved oil and natural gas reserves increased 24% from 85.1 million BOE at December 31,
2015 to 105.8 million BOE at December 31, 2016. We added 42.0 million BOE in proved oil and natural gas reserves
through extensions and discoveries throughout 2016, approximately 4.1 times our 2016 annual production of
10.2 million BOE. Our proved oil reserves grew 25% from approximately 45.6 million Bbl at December 31, 2015 to
approximately 57.0 million Bbl at December 31, 2016. Our proved natural gas reserves increased 24% from
236.9 Bcf at December 31, 2015 to 292.6 Bcf at December 31, 2016. This increase in proved oil and natural gas
reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2016.
We incurred approximately 11.2 million BOE in net downward revisions to our proved reserves during 2016 as
a result of the reclassiﬁcation of certain proved undeveloped reserves to contingent resources, primarily due to
the lower oil and natural gas prices used to estimate proved reserves at December 31, 2016, as compared to

FORM 10-K PART I

2016 ANNUAL REPORT

December 31, 2015. These contingent resources may be reclassiﬁed to proved undeveloped reserves in future
periods should the oil and natural gas prices used to estimate proved oil and natural gas reserves improve from
the prices at December 31, 2016. Our proved reserves to production ratio at December 31, 2016 was 10.4, an
increase of 11% from 9.4 at December 31, 2015.

The Standardized Measure of our total proved oil and natural gas reserves increased 9% from $529.2 million at

December 31, 2015 to $575.0 million at December 31, 2016. The PV-10 of our total proved oil and natural gas
reserves increased 7% from $541.6 million at December 31, 2015 to $581.5 million at December 31, 2016. The
increase in our Standardized Measure and PV-10 are primarily a result of our delineation and development
operations in the Delaware Basin during 2016, which was partially impacted by the lower weighted average oil and
natural gas prices used to estimate proved reserves at December 31, 2016, as compared to December 31, 2015.
The unweighted arithmetic averages of ﬁrst-day-of-the-month oil and natural gas prices used to estimate proved
reserves at December 31, 2016 were $39.25 per Bbl and $2.48 per MMBtu, a decrease of 17% and 4%, respectively,
as compared to average oil and natural gas prices of $46.79 per Bbl and $2.59 per MMBtu used to estimate
proved reserves at December 31, 2015. Our total proved reserves were made up of approximately 54% oil and
46% natural gas at December 31, 2016 and December 31, 2015.

Our proved developed oil and natural gas reserves increased 28% from 34.0 million BOE at December 31, 2015

to 43.7 million BOE at December 31, 2016 due primarily to our delineation and development operations in the
Delaware Basin. Our proved developed oil reserves increased 32% from 17.1 million Bbl at December 31, 2015 to
22.6 million Bbl at December 31, 2016. Our proved developed natural gas reserves increased 25% from 101.4 Bcf
at December 31, 2015 to 126.8 Bcf at December 31, 2016.

The following table summarizes changes in our estimated proved developed reserves at December 31, 2016.

As of December 31, 2015

Extensions and discoveries
Revisions of prior estimates
Production
Conversion of proved undeveloped to proved developed

As of December 31, 2016

(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Proved
Developed
Reserves

(MBOE)(1)

34,037
12,583
408
(10,180)
6,883
43,731

Our proved undeveloped oil and natural gas reserves increased from 51.1 million BOE at December 31, 2015
to 62.0 million BOE at December 31, 2016. Our proved undeveloped oil and natural gas reserves increased from
28.5 million Bbl and 135.5 Bcf, respectively, at December 31, 2015 to 34.4 million Bbl and 165.9 Bcf, respectively,
at December 31, 2016, primarily as a result of our delineation and development operations in the Delaware Basin.

At December 31, 2016, we had no proved undeveloped reserves in our estimates that remained undeveloped

for ﬁve years or more following their initial booking, and we currently have plans to use anticipated capital
resources to develop the proved undeveloped reserves remaining as of December 31, 2016 within ﬁve years of
booking these reserves.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2016.

As of December 31, 2015

Extensions and discoveries
Revisions of prior estimates
Conversion of proved undeveloped to proved developed

As of December 31, 2016

(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Proved
Undeveloped
Reserves

(MBOE)(1)

51,090
29,408
(11,594)
(6,883)
62,021

The following table sets forth, since 2013, proved undeveloped reserves converted to proved developed reserves

during each year and the investments associated with these conversions (dollars in thousands).

Proved Undeveloped Reserves
Converted to
Proved Developed Reserves

Oil

Natural Gas

(MBbl)

(Bcf)

Investment in
Conversion
of Proved
Undeveloped
Reserves
to Proved
Total Developed
Reserves

(MBOE)(1)

2013
2014
2015
2016

Total

2,944
3,780
2,854
4,705
14,283

8.3
44.7
23.4
13.1
89.5

4,334
11,223
6,747
6,883
29,187

$115,699
201,950
104,989
94,579
$517,217

(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

The following table sets forth additional summary information by operating area with respect to our estimated

net proved reserves at December 31, 2016.

Southeast New Mexico/West Texas:

Delaware Basin

South Texas:

Eagle Ford (5)

Northwest Louisiana/East Texas:

Haynesville
Cotton Valley
Area Total
Total

(6)

Net Proved Reserves (1)

Oil

(MBbl)

Natural Gas

Oil
Equivalent

Standardized
Measure(2)

PV-1VV 0 (3)

(Bcf)

(MBOE)(4)

(in millions)

46,873

195.1

79,388

$ 446.0

$ 451.0

10,066

19.3

13,298

85.6

86.6

—
38
38
56,977

74.5
3.7
78.2
292.6

12,414
652
13,066
105,752

41.5
1.9
43.4
$ 575.0

42.0
1.9
43.9
$ 581.5

(1) Numbers in table may not total due to rounding.

(2) Standardized Measure represents the present value of estimated future net cash ﬂows from proved reserves, less estimated future

(3) PV-10 is a non-GAAP ﬁnancial measure and generally differs from Standardized Measure, the most directly comparable GAAP ﬁnancial measure,

because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our
properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies
and of the potential return on investment related to the companies’ properties without regard to the speciﬁc tax characteristics of such entities.
Our PV-10 at December 31, 2016 may be reconciled to our Standardized Measure of discounted future net cash ﬂows at such date by reducing
our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2016
were approximately $6.5 million.

(4) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(5) Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from

the San Miguel formation in Zavala County, Texas.

(6) Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.

FORM 10-K PART I

2016 ANNUAL REPORT

Technology Used to Establish Reserves

Under current SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of

geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a
given date forward, from known reservoirs and under existing economic conditions, operating methods and
government regulations. The term “reasonable certainty” implies a high degree of conﬁdence that the quantities of
oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established
using techniques that have been proven effective by actual production from projects in the same reservoir or an
analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable
technology is a grouping of one or more technologies (including computational methods) that have been ﬁeld
tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the
formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies
that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data
used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core
analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for
proved developed producing wells were estimated using production performance and material balance methods.
Certain new producing properties with little production history were forecast using a combination of production
performance and analogy to offset production. Non-producing reserves estimates for both developed and
undeveloped properties were forecast using either volumetric and/or analogy methods.

Internal Control Over Reserves Estimation Process

We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity,

accuracy and timeliness of the data used in our reserves estimation process. Our Senior Vice President of Reservoir
Engineering and Chief Technology Ofﬁcer is primarily responsible for overseeing the preparation of our reserves
estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M
University, is a Licensed Professional Engineer in the State of Texas and has over 39 years of industry experience.
Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by
Netherland, Sewell & Associates, Inc., independent reservoir engineers. The Operations and Engineering Committee
of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the
reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors,
including members of our Audit Committee.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

ACREAGE SUMMARY

December 31, 2016.

Southeast New Mexico/West Texas:

Delaware Basin

South Texas:
Eagle Ford

Northwest Louisiana/East Texas:

Haynesville
Cotton Valley

VV
Area Total (1)
Total (2)

Developed Acres

Undeveloped Acres

Total Acres

Gross

Net

Gross

Net

Gross

Net

79,087

33,699

84,616

60,613

163,703

94,312

26,402

23,682

4,267

4,095

30,669

27,777

16,739
18,108
22,030
127,519

9,088
16,078
19,761
77,142

3,366
3,506
4,032
92,915

3,364
2,993
3,517
68,225

20,105
21,614
26,062
220,434

12,452
19,071
23,278
145,367

(1) Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation.
Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and
East Texas.

(2) During the year ended December 31, 2016, we released all of our acreage in Wyoming, Utah and Idaho.

UNDEVELOPED ACREAGE EXPIRATION

The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2016

that will expire over the next three years by operating area unless production is established within the spacing
units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or
continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped
acreage expiring in 2020 and beyond represents an immaterial amount of our overall undeveloped acreage.

Southeast New Mexico/West Texas:

Delaware Basin (1)

South Texas:
Eagle Ford

Northwest Louisiana/East Texas:

Haynesville
VV
Cotton Valley
Area Total (2)
Total

Acres Expiring 2017

Acres Expiring 2018

Acres Expiring 2019

Gross

Net

Gross

Net

Gross

Net

17,604

7,987

39,704

25,294

15,404

9,086

1,435

1,375

896

753

204

156

—
—
—
19,039

—
—
—
9,362

—
—
—
40,600

—
—
—
26,047

326
—
326
15,934

324
—
324
9,566

(1) Approximately 54% of the acreage expiring in the next three years is associated with our Twin Lakes asset area in northern Lea County,

New Mexico. Most of these leases can be extended for an additional two years, should we choose to do so, by paying an additional lease bonus.
We also expect to hold or extend portions of the remaining expiring acreage outside of our Twin Lakes asset area in 2017 through our 2017
drilling activities or by paying an additional lease bonus, where applicable.

(2) Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation.
Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and
East Texas.

FORM 10-K PART I

2016 ANNUAL REPORT

Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective
primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of
the primary term or production from the acreage has been established prior to such date, in which event the lease
will remain in effect until the cessation of production in commercial quantities in most cases. We also have options
to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the
primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our
acreage; however, there may be third-party leases that become effective immediately if our leases expire at the end
of their respective terms and production has not been established prior to such date or operations are not conducted
to maintain the leases in effect beyond the primary term. As of December 31, 2016, our leases are primarily fee
and state leases with primary terms of three to ﬁve years and federal leases with primary terms of 10 years. We
believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and
royalty interests.

DRILLING RESULTS

The following table summarizes our drilling activity for the years ended December 31, 2016, 2015 and 2014.

Development Wells

Productive
Dry

Exploration Wells

Productive
Dry
Total Wells

Productive
Dry

Year Ended December 31,

2016

2015

2014

Gross

Net

Gross

Net

Gross

Net

44
—

28
—

72
—

23.5
—

15.6
—

39.1
—

53
—

26.7
—

89
—

28
—

81
—

17.5
—

44.2
—

12
—

101
—

39.9
—

10.6
—

50.5
—

MARKETING AND CUSTOMERS

Our crude oil is generally sold under short-term, extendable and cancellable agreements with unafﬁliated

purchasers based on published price bulletins reﬂecting an established ﬁeld posting price. As a consequence, the
prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with
the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down
independently of any relationship between the crude oil and natural gas markets. Transportation costs related to
moving crude oil and liquids are also deducted from the price received for crude oil and liquids.

Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas

produced by us is sold at various delivery points at or near producing wells to both unafﬁliated independent marketing
companies and unafﬁliated midstream companies. The prices we receive are based on various pipeline indices
less any associated fees. When there is an opportunity to do so, we may have our natural gas processed at our or
third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the
extracted liquids based on either a negotiated percentage of the proceeds that are generated from the sale of the
liquids, or other negotiated pricing arrangements using then-current market pricing less ﬁxed rate processing,
transportation and fractionation fees.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

The prices we receive for our oil and natural gas production ﬂuctuate widely. Factors that, directly or indirectly,
cause price ﬂuctuations include the level of demand for oil and natural gas, the actions of OPEC, weather conditions,
hurricanes in the Gulf Coast region, oil and natural gas storage levels, domestic and foreign governmental
regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the
domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions.
Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues,
proﬁtability and cash ﬂows. Short-term disruptions of our oil and natural gas production occur from time to time
due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance
and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities
and ability to maintain a steady source of revenue. See “Risk Factors — Our Success Is Dependent on the Prices of
Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely
Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.”

For the years ended December 31, 2016, 2015 and 2014, we had three signiﬁcant purchasers that accounted for

approximately 48%, 59% and 68%, respectively, of our total oil, natural gas and natural gas liquids revenues. Due
to the nature of the markets for oil, natural gas and natural gas liquids, we do not believe that the loss of any one of
these purchasers would have a material adverse impact on our ﬁnancial condition, results of operations or cash
ﬂows for any signiﬁcant period of time.

TITLE TO PROPERTIES

We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil
and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and
other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the
undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to
these contractual interests will be contingent upon our satisfactory fulﬁllment of these obligations. Our properties
are also subject to customary royalty interests, liens incident to ﬁnancing arrangements, operating agreements,
taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value
of these properties. We intend to maintain our leasehold interests by conducting operations, making lease rental
payments or producing oil and natural gas from wells in paying quantities, where required, prior to expiration of
various time periods to avoid lease termination. See “Risk Factors — We May Incur Losses or Costs as a Result of
Title Deﬁciencies in the Properties in Which We Invest.”

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject

to customary encumbrances, such as customary interests generally retained in connection with the acquisition of
real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other
burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe
that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use
and operation of these properties in the conduct of our business. In addition, we believe that we have obtained
sufﬁcient right-of-way grants and permits from public authorities and private parties for us to operate our business.

FORM 10-K PART I

2016 ANNUAL REPORT

SEASONALITY

Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease

during summer months. To lessen seasonal demand ﬂuctuations, pipelines, utilities, local distribution companies
and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter
requirements during the summer. However, increased summertime demand for electricity can place increased
demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the
summer driving season, although oil prices are impacted more signiﬁcantly by global supply and demand. Seasonal
anomalies, such as mild winters, sometimes lessen these ﬂuctuations. Certain of our drilling, completion and
other operations are also subject to seasonal limitations where equipment may not be available during periods of
peak demand or where weather conditions and events result in delayed operations. See “Risk Factors —
Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and Markets
Relating to a Particular Area Could Have a Material Impact on Our Business.”

COMPETITION

The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural
gas companies for exploration opportunities, acreage and property acquisitions, as well as drilling rig contracts and
other equipment and labor required to drill, operate and develop our properties. We also compete with public and
private midstream companies for natural gas gathering, processing and compression opportunities, as well as salt
water disposal activities in the areas in which we operate.

Many of our competitors have substantially greater ﬁnancial resources, staffs, facilities and other resources. In

addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and
regulations more easily than we can, which would adversely affect our competitive position. These competitors may
be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas
properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of
properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their
own drilling rigs and hydraulic fracturing equipment.

Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream

services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment. We have been conducting ﬁeld operations since
2004 while many of our competitors may have a longer history of operations. Additionally, most of our competitors
have demonstrated the ability to operate through industry cycles.

The oil and natural gas industry also competes with other energy-related industries in supplying the energy and

fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the
Oil and Natural Gas Industry Is Intense, Making It More Difﬁcult for Us to Acquire Properties, Market Oil and Natural
Gas and Secure Trained Personnel.”

FORM 10-K PART I

MATADOR RESOURCES COMPANY

REGULATION

Oil and Natural Gas Regulation

Our oil and natural gas exploration, development, production, midstream and related operations are subject to
extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations
can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil
and natural gas industry increases our cost of doing business and affects our proﬁtability. Because these laws, rules
and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we
are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or
will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory
requirements and restrictions that affect our operations. We cannot predict the impact of future government
regulation on our properties or operations.

Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and

reports concerning operations and impose other requirements relating to the exploration, development and
production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and
natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the
establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and
restoration of properties upon which wells are drilled, the prohibition or restriction on venting or ﬂaring natural gas,
the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment
of wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted
statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies
have, from time to time, imposed price controls and limitations on production by restricting the rate of ﬂow of oil
and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover,
each state generally imposes a production or severance tax with respect to the production and sale of oil, natural
gas and natural gas liquids within its jurisdiction.

Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies
of the states in which we operate. These leases contain various restrictions on access and development and other
requirements that may impede our ability to conduct operations on the acreage represented by these leases.

Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability,

terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of
natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas
Act of 1938, or the NGA, as well as under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Since
1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making
natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory
basis. The natural gas industry has historically, however, been heavily regulated, and we can give no assurance that
the current less stringent regulatory approach of FERC will continue.

In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy

Policy Act, among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC
to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce and to
signiﬁcantly increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders
thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market
manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to
third-party damage claims.

FORM 10-K PART I

2016 ANNUAL REPORT

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate
regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural
gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate
natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in
which we operate will not affect our operations in any way that is materially different from our competitors that
are similarly situated.

Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and

intrastate crude oil gathering facilities are also exempt from FERC’s jurisdiction under the Interstate Commerce Act.
We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to
establish a pipeline’s status as a gatherer not subject to FERC jurisdiction, and that the crude oil pipelines in our
gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate
facility not subject to FERC jurisdiction. State regulation of gathering facilities generally includes various safety,
environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation.

The price we receive from the sale of oil and natural gas liquids will be affected by the availability, terms and cost

of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates
based on an inﬂation index, though other rate mechanisms may be used in speciﬁc circumstances. Intrastate oil
pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to
state. We are not able to predict with certainty the effects, if any, of these regulations on our operations.

In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA, among other

things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or
petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission
may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for
violations thereunder.

The Pipeline and Hazardous Materials Safety Administration, or PHMSA, imposes pipeline safety requirements

on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act
and the Hazardous Liquid Pipeline Safety Act, as amended. In recent years, pursuant to these laws and, in addition,
the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has expanded its regulation of
gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion
control, public education programs, maximum allowable operating pressure limits and other requirements.
Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements.
On April 8, 2016, PHMSA published a notice of proposed rulemaking (NPRM) that would amend existing
integrity management requirements, expand assessment and repair requirements in areas with medium population
densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt.
On January 13, 2017, PHMSA issued, but has yet to publish, a similar proposed rule for hazardous liquids (i.e., oil)
pipelines and gathering lines. In addition, states have adopted regulations, similar to existing PHMSA regulations,
for intrastate gathering and transmission lines.

Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or

costly safety standards, which could result in increased operating costs or operational delays.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

U.S. Federal and State Taxation

The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural

gas products we sell and, for many of our wells, sales and use taxes on signiﬁcant portions of our drilling and
operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction
of hydrocarbons, and additional increases may occur. In addition, from time to time there has been a signiﬁcant
amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals,
including proposals that would eliminate allowing small U.S. oil and natural gas companies to deduct intangible
drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and
our ﬁnancial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become
Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available
with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which
Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.”

Hydraulic Fracturing Policies and Procedures

We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that
we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training
programs taught by industry professionals. Although average drilling and completion costs for each area will vary,
as will the cost of each well within a given area, on average approximately one-half to two-thirds of the total
well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on
hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling
and completion of our wells and are included in and funded through our normal capital expenditure budget.
A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs
and adversely affect our business and ﬁnancial results. See “Risk Factors — Federal and State Legislation and
Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating
Restrictions or Delays.”

The protection of groundwater quality is important to us. We believe that we follow all state and federal

regulations and apply industry standard practices for groundwater protection in our operations. These measures are
subject to close supervision by state and federal regulators (including the Bureau of Land Management, or the
BLM, with respect to federal acreage).

Although rare, if and when the cement and steel casing used in well construction requires remediation, we deal

with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and
temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other
appropriate remedial measures.

The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made

propping agents. We use major hydraulic fracturing service companies who track and report chemical additives
that are used in fracturing operations as required by the appropriate governmental agencies. These service
companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect
the environment through rigorous safety procedures, and also work to develop more environmentally friendly
fracturing ﬂuids. We also follow safety procedures and monitor all aspects of our fracturing operations in an attempt
to ensure environmental protection. We do not pump any diesel in the ﬂuid systems of any of our fracture
stimulation procedures.

FORM 10-K PART I

2016 ANNUAL REPORT

While current fracture stimulation procedures utilize a signiﬁcant amount of water, we typically recover less than

10% of this fracture stimulation water before produced salt water becomes a signiﬁcant portion of the ﬂuids
produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated disposal
facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have also been
recycling a portion of our produced salt water in certain of our Delaware Basin asset areas. Recycling produced salt
water mitigates the need for salt water disposal and also provides cost savings to us.

Environmental Regulation

The exploration, development, production, gathering and processing of oil and natural gas, including the operation

of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and
regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and
operating oil and natural gas wells, midstream facilities and salt water injection and disposal wells. Our activities are
subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990,
or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation
and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA,
the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as
comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation,
storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM,
that may result from our oil and natural gas operations. Administrative, civil and criminal ﬁnes and penalties may be
imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations
require the acquisition of permits or other governmental authorizations before undertaking some activities, limit
or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of
pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws
and regulations and do not expect that these laws and regulations will have a material adverse impact on us.

The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude

oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in
the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner
or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several ﬁnancial
liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is
covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal
enforcement action.

The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced
waters, ﬁll materials and other materials into navigable waters. These controls have become more stringent over the
years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge
pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands.
The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized
discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination
resulting from such discharges.

CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the

original conduct, on various classes of persons that are considered to have contributed to the release of a
“hazardous substance” into the environment. These persons include the owner or operator of the site where the
release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances
found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject
to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural
resources. In addition, it is not uncommon for neighboring landowners and other third parties to ﬁle claims for

FORM 10-K PART I

MATADOR RESOURCES COMPANY

personal injury and property damage allegedly caused by hazardous substances released into the environment.
Although CERCLA generally exempts petroleum from the deﬁnition of hazardous substances, our operations may,
and in all likelihood will, involve the use or handling of materials that may be classiﬁed as hazardous substances
under CERCLA.

RCRA and comparable state and local statutes govern the management, including treatment, storage and

disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste
in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many
wastes associated with crude oil and natural gas exploration and production to be classiﬁed as nonhazardous waste.
A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate
fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate
the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modiﬁcations of
this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes,
would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as
well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent
and costly disposal requirements than nonhazardous wastes.

The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources,
including oil and natural gas production. These laws and any implementing regulations impose stringent air permit
requirements and require us to obtain pre-approval for the construction or modiﬁcation of certain projects or
facilities expected to produce air emissions, or to use speciﬁc equipment or technologies to control emissions.
See “Risk Factors — New Regulations on All Emissions from Our Operations Could Cause Us to Incur Signiﬁcant
Costs.” Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-
compliance with air permits or other requirements of the federal CAA and associated state laws and regulations.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent

and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially
adversely affect our operations and ﬁnancial condition, as well as those of the oil and natural gas industry in general.
For instance, recent scientiﬁc studies have suggested that emissions of certain gases, commonly referred to as
“greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s
atmosphere. Based on these ﬁndings, the Environmental Protection Agency, or the EPA, has begun adopting and
implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing
provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions
could, and in all likelihood would, require us to incur increased operating costs adversely affecting our proﬁts and
could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and
natural gas. See “Risk Factors — Legislation or Regulations Restricting Emissions of Greenhouse Gases Could
Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and Natural Gas Liquids We
Produce while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Signiﬁcant
Costs in Preparing for or Responding to Those Effects” and “Risk Factors — New Regulations on All Emissions
from Our Operations Could Cause Us to Incur Signiﬁcant Costs.”

Underground injection is the subsurface placement of ﬂuid through a well, such as the reinjection of brine
produced and separated from oil and natural gas production. In our industry, underground injection not only allows
us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil
production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary
objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of
ﬂuids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by

FORM 10-K PART I

2016 ANNUAL REPORT

underground injection is subject to stricter requirements than the disposal of produced water. As of December 31,
2016, we owned and operated twelve underground injection wells and we expect to own and operate similar
wells in the future. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could
subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of
underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of ﬂawed well
design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location
and operation of underground injection wells. We do not expect these developments to have a material adverse
effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations,

see “— Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing regulatory scrutiny
of hydraulic fracturing, which is generally exempted from federal regulation as underground injection (unless diesel
is a component of the fracturing ﬂuid) under the SDWA. The process of hydraulic fracturing is typically regulated
by state oil and natural gas commissions. Some states and localities have placed additional regulatory burdens upon
hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. If the exemption
for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level
imposing any restrictions on the use of hydraulic fracturing, this could have a signiﬁcant impact on our ﬁnancial
condition, results of operations and cash ﬂows. Additional burdens upon hydraulic fracturing, such as reporting or
permitting requirements, will result in additional expense and delay in our operations. Restrictions on hydraulic
fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing
Could Result in Increased Costs and Additional Operating Restrictions or Delays.”

Oil and natural gas exploration and production, operations and other activities have been conducted at some of our

properties by previous owners and operators. Materials from these operations remain on some of the properties,
and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of
producing properties from whom we acquire the properties against some of the liability for environmental claims
associated with the properties. While we do not believe that costs we incur for compliance with environmental
regulations and remediating previously or currently owned or operated properties will be material, we cannot
provide any assurances that these costs will not result in material expenditures that adversely affect our proﬁtability.

Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing
leaks, of oil or other materials may occur, and we may incur costs for waste handling and environmental compliance.
It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in
varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated
in scale, ﬁlm and sludge in equipment that comes in contact with crude oil and natural gas production and processing
streams. Some states, including Texas, have enacted regulations governing the handling, treatment, storage
and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate.
Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to
comply with the applicable environmental regulations may, in certain circumstances, be attributable to us.

We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication

Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and
Reauthorization Act and similar state statutes require us to organize information about hazardous materials used,
released or produced in our operations. Certain of this information must be provided to employees, state and
local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in
OSHA workplace standards.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant

to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely
affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act.
The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part
of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material
restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas
operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions
on drilling activity designed to protect certain wildlife in the Delaware Basin. See “Risk Factors—We Are Subject to
Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Signiﬁcant
Expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions.

We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are

material in relation to our total capital expenditures as a result of environmental laws and regulations, but since
these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance.
We have no assurance that more stringent laws and regulations protecting the environment will not be adopted
or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the
future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental
Laws, Which Could Require Signiﬁcant Expenditures.”

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may

affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement
policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport,
disposal or remediation requirements could have a material adverse effect on our operations and ﬁnancial condition.
We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases
or spills may occur in the course of our operations, and we have no assurance that we will not incur signiﬁcant costs
and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural
resources or persons.

We maintain insurance against some, but not all, potential risks and losses associated with our industry and
operations. We do not currently carry business interruption insurance. For some risks, we may not obtain insurance
if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution
and environmental risks generally are not fully insurable. If a signiﬁcant accident or other event occurs and is not
fully covered by insurance, it could materially adversely affect our ﬁnancial condition, results of operations and
cash ﬂows.

OFFICE LEASE

Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas
75240. See Note 13 to the consolidated ﬁnancial statements in this Annual Report for more details regarding our
ofﬁce lease. Such information is incorporated herein by reference.

FORM 10-K PART I

2016 ANNUAL REPORT

EMPLOYEES

At December 31, 2016, we had 165 full-time employees. We believe that our relationships with our employees

are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the
services of independent consultants and contractors to perform various professional services, particularly in the
areas of geology and geophysics, land, production operations, construction, design, well site surveillance and
supervision, permitting and environmental assessment and legal and income tax preparation and accounting
services. Independent contractors, at our request, drill all of our wells and usually perform ﬁeld and on-site production
operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching,
inspection and testing. If signiﬁcant opportunities for company growth arise and require additional management and
professional expertise, we will seek to employ qualiﬁed individuals to ﬁll positions where that expertise is
necessary to develop those opportunities.

AVAILABLE INFORMATION

Our Internet website address is www.matadorresources.com. We make available, free of charge, through our

website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and
amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the
charters of our Audit Committee, Compensation Committee, Corporate Governance Committee, Executive
Committee and Nominating Committee, and our Code of Ethics and Business Conduct for Ofﬁcers, Directors and
Employees, are available through our website, and we also intend to disclose any amendments to our Code of
Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Ofﬁcer, Chief Financial Ofﬁcer
or Chief Accounting Ofﬁcer, on our website. All of these corporate governance materials are available free of
charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln
Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be
incorporated by reference into this Annual Report or any other report or document we ﬁle and any reference to our
website is intended to be an inactive textual reference only.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

ITEM 1A. RISK FACTORS.

RISKS RELATED TO THE OIL AND NATURAL GAS INDUSTRY AND OUR BUSINESS

Our Success Is Dependent on the Prices of Oil and Natural Gas. Continued Low Oil and Natural Gas Prices
and the Continued Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to
Meet Our Capital Expenditure Requirements and Financial Obligations.

The prices we receive for our oil and natural gas heavily inﬂuence our revenue, proﬁtability, cash ﬂow available

for capital expenditures, access to capital, borrowing capacity under our Credit Agreement and future rate of
growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide ﬂuctuations in response
to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been
volatile and will likely continue to be volatile in the future. During 2016, the average price of oil was $43.40 per Bbl,
based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date, and the
average price of natural gas was $2.55 per MMBtu, based upon the NYMEX Henry Hub natural gas futures contract
price for the earliest delivery date. Starting in February and March of 2016, respectively, oil and natural gas prices
began to increase from their most recent lows. Oil prices increased 106% from $26.21 per Bbl in mid-February 2016
to $54.06 per Bbl in late December 2016, and natural gas prices increased 140% from $1.64 per MMBtu in early
March 2016 to $3.93 per MMBtu in late December 2016.

Further, because we use the full-cost method of accounting, we perform a ceiling test quarterly that may be
impacted by declining prices of oil and natural gas. Signiﬁcant price declines caused us to recognize full-cost ceiling
impairments in each of the quarters of 2015 and in the ﬁrst two quarters of 2016, and should prices decline again,
we may recognize further full-cost ceiling impairments. Such full-cost ceiling impairments reduce the book value of
our net tangible assets, retained earnings and shareholders’ equity but do not impact our cash ﬂows from operations,
liquidity or capital resources. See “—We May Be Required to Write Down the Carrying Value of Our Proved
Properties under Accounting Rules and These Write-Downs Could Adversely Affect Our Financial Condition.”

The prices we receive for our production, and the levels of our production, depend on numerous factors. These

factors include, but are not limited to, the following:

(cid:85)

the domestic and foreign supply of, and demand for, oil and natural gas;

the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil
companies relating to oil price and production controls;

the prices and availability of competitors’ supplies of oil and natural gas;

the price and quantity of foreign imports;

the impact of U.S. dollar exchange rates on oil and natural gas prices;

(cid:85) domestic and foreign governmental regulations and taxes;

(cid:85) speculative trading of oil and natural gas futures contracts;

(cid:85)

the availability, proximity and capacity of gathering, processing and transportation systems for natural gas;

the availability of reﬁning capacity;

the prices and availability of alternative fuel sources;

(cid:85) weather conditions and natural disasters;

(cid:85) political conditions in or affecting oil and natural gas producing regions or countries, including the

United States, Middle East, South America and Russia;

FORM 10-K PART I

2016 ANNUAL REPORT

(cid:85)

the continued threat of terrorism and the impact of military action and civil unrest;

(cid:85) public pressure on, and legislative and regulatory interest within, federal, state and local governments to

stop, signiﬁcantly limit or regulate hydraulic fracturing activities;

(cid:85)

the level of global oil and natural gas inventories and exploration and production activity;

the impact of energy conservation efforts;

technological advances affecting energy consumption; and

(cid:85) overall worldwide economic conditions.

These factors make it difﬁcult to predict future commodity price movements with any certainty. Substantially all

of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices
and are not pursuant to long-term ﬁxed price contracts. Further, oil prices and natural gas prices do not necessarily
ﬂuctuate in direct relation to each other.

Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and

natural gas that we can produce economically and could reduce the amount we may borrow under our Credit
Agreement. Should oil or natural gas prices decrease to economically unattractive levels and remain at economically
unattractive levels for an extended period of time, we may elect in the future to delay some of our exploration
and development plans for our prospects, or to cease exploration or development activities on certain prospects due
to the anticipated unfavorable economics from such activities, each of which could have a material adverse effect
on our business, ﬁnancial condition, results of operations and reserves. In addition, such declines in commodity
prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding
borrowings under our Credit Agreement at any time, we would be required to provide additional collateral
satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufﬁcient to cover such
excess or repay the deﬁcit in equal installments over a period of six months.

Our Exploration, Development, Exploitation and Midstream Projects Require Substantial Capital
Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be
Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.

Our exploration, development, exploitation and midstream activities are capital intensive. Our cash, operating
cash ﬂows, contributions from our joint venture partners and potential future borrowings under our Credit Agreement
or otherwise may not be sufﬁcient to fund all of our future acquisitions or future capital expenditures. The rate of
our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine
to be acceptable.

We may sell additional equity securities or issue additional debt securities to raise capital. If we succeed in

selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions,
the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences
or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of
new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our
business activities.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Our cash ﬂows from operations and access to capital are subject to a number of variables, including:

(cid:85) our estimated proved oil and natural gas reserves;

(cid:85)

the amount of oil and natural gas we produce from existing wells;

the prices at which we sell our production;

the costs of developing and producing our oil and natural gas reserves;

the costs of constructing, operating and maintaining our midstream facilities;

(cid:85) our ability to acquire, locate and produce new reserves;

(cid:85)

the ability and willingness of banks to lend to us; and

(cid:85) our ability to access the equity and debt capital markets.

In addition, the possible occurrence of future events, such as further decreases in the prices of oil and natural

gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions,
ﬁnancial market disruptions, general economic recessions, oil and natural gas industry recessions, large company
bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions
in the ﬁnancial and capital markets, has caused ﬁnancial institutions, credit rating agencies and the public to more
closely review the ﬁnancial statements, capital structures and earnings of public companies, including energy
companies. Such events have constrained the capital available to the energy industry in the past, and such events
or similar events could adversely affect our access to funding for our operations in the future.

If our revenues decrease as a result of lower oil and natural gas prices, operating difﬁculties, declines in reserves

or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain
our operations at current levels, further develop and exploit our current properties or invest in certain exploration
opportunities. Alternatively, to fund acquisitions, increase our rate of growth, develop our properties or pay for
higher service costs, we may decide to alter or increase our capitalization substantially through the issuance of debt
or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and
natural gas producing assets or acreage, the borrowing of funds or otherwise to meet any increase in capital
spending. If we are unable to raise additional capital from available sources at acceptable terms, our business,
ﬁnancial condition and future results of operations could be adversely affected.

Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree
of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our Business.

Exploring for and developing hydrocarbon reserves involves a high degree of operational and ﬁnancial risk, which

precludes us from deﬁnitively predicting the costs involved and time required to reach certain objectives. Our
drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that
will require substantial additional interpretation before they can be drilled. The budgeted costs of planning, drilling,
completing and operating wells are often exceeded and such costs can increase signiﬁcantly due to various
complications that may arise during drilling, completion and operation. Before a well is spud, we may incur signiﬁcant
geological, geophysical and land costs, including seismic costs, which are incurred whether or not a well eventually
produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a much greater risk
of loss than development wells. The analogies we draw from available data from other wells, more fully explored
locations or producing ﬁelds may not be applicable to our drilling locations. If our actual drilling and development
costs are signiﬁcantly more than our estimated costs, we may not be able to continue our operations as proposed
and could be forced to modify our drilling plans accordingly.

FORM 10-K PART I

2016 ANNUAL REPORT

If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs
will be found or produced. We may drill or participate in new wells that are not productive. We may drill or participate
in wells that are productive, but that do not produce sufﬁcient net revenues to return a proﬁt after drilling,
operating and other costs. There is no way to afﬁrmatively determine in advance of drilling and testing whether any
particular location will yield oil or natural gas in sufﬁcient quantities to recover exploration, drilling and completion
costs or to be economically viable. Even if sufﬁcient amounts of oil or natural gas exist, we may damage the
potentially productive hydrocarbon-bearing formation or experience mechanical difﬁculties while drilling or completing
the well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and
proﬁtability of a well may be negatively affected by a number of additional factors, including the following:

(cid:85) general economic and industry conditions, including the prices received for oil and natural gas;

(cid:85) shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualiﬁed

personnel;

(cid:85) potential drainage of oil and natural gas from our properties by adjacent operators;

(cid:85)

loss of or damage to oilﬁeld development and service tools;

(cid:85) accidents, equipment failures or mechanical problems;

(cid:85)

title defects of the underlying properties;

increases in severance taxes;

(cid:85) adverse weather conditions that delay drilling activities or cause producing wells to be shut in;

(cid:85) domestic and foreign governmental regulations; and

(cid:85) proximity to and capacity of gathering, processing and transportation facilities.

Furthermore, our exploration and production operations involve using some of the latest drilling and completion
techniques developed by us and our service providers. For example, risks that we face while drilling and completing
horizontal wells include, but are not limited to, the following:

(cid:85)

landing our wellbore in the desired drilling zone;

(cid:85) staying in the desired drilling zone while drilling horizontally through the formation;

(cid:85)

running our casing the entire length of the wellbore;

fracture stimulating the planned number of stages; and

(cid:85) being able to run tools and other equipment consistently through the horizontal wellbore.

If we do not drill productive and proﬁtable wells in the future, our business, ﬁnancial condition, results of

operations, cash ﬂows and reserves could be materially and adversely affected.

The Borrowing Base under Our Credit Agreement Is Subject to Periodic Redetermination.

The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by
the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and
June 30 of each year, respectively. Both we and the lenders may request an unscheduled redetermination of the
borrowing base once each between scheduled redetermination dates. In addition, our lenders have the ﬂexibility to
reduce our borrowing base due to a variety of factors, some of which may be beyond our control. As of February 22,
2017, our borrowing base was $400.0 million, and we had no outstanding borrowings under, and approximately
$0.8 million in outstanding letters of credit issued pursuant to, the Credit Agreement. We could be required to repay
a portion of any outstanding bank debt to the extent that, after a redetermination, our outstanding borrowings at

FORM 10-K PART I

MATADOR RESOURCES COMPANY

such time exceeded the redetermined borrowing base. We may not have sufﬁcient funds to make such
repayments, which could result in a default under the terms of the Credit Agreement and an acceleration of the
loans thereunder requiring us to negotiate renewals, arrange new ﬁnancing or sell signiﬁcant assets, all of which
could have a material adverse effect on our business and ﬁnancial results.

The Terms of the Agreements Governing Our Outstanding Indebtedness May Restrict Our Current and
Future Operations, Particularly Our Ability to Respond to Changes in Business or to Take Certain Actions.

Our Credit Agreement and the indenture governing our senior notes contain, and any future indebtedness we
incur will likely contain, a number of restrictive covenants that impose signiﬁcant operating and ﬁnancial restrictions,
including restrictions on our ability to engage in acts that may be in our best long-term interest. One or more of
these agreements include covenants that, among other things, restrict our ability to:

(cid:85)

incur or guarantee additional debt or issue certain types of preferred stock;

(cid:85) pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;

(cid:85)

transfer or sell assets;

(cid:85) make certain investments;

(cid:85) create certain liens;

(cid:85) enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as deﬁned

in the indenture) to us;

(cid:85) consolidate, merge or transfer all or substantially all of our assets;

(cid:85) engage in transactions with afﬁliates; and

(cid:85) create unrestricted subsidiaries.

A breach of any of these covenants could result in an event of default under our Credit Agreement and the

indenture governing our outstanding senior notes. For example, our Credit Agreement requires us to maintain a debt
to EBITDA ratio, which is deﬁned as total debt outstanding divided by a rolling four quarter EBITDA calculation, of
4.25 or less. Low oil and natural gas prices or any decline in the prices of oil or natural gas may adversely impact our
EBITDA, cash ﬂows and debt levels, and therefore our ability to comply with this covenant. Upon the occurrence
of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be
immediately due and payable and all applicable commitments to extend further credit could be terminated. If
indebtedness under our Credit Agreement or indenture is accelerated, there can be no assurance that we will have
sufﬁcient assets to repay such indebtedness. The operating and ﬁnancial restrictions and covenants in these debt
agreements and any future ﬁnancing agreements could adversely affect our ability to ﬁnance future operations or
capital needs or to engage in other business activities.

We May Not Be Able to Generate Sufﬁcient Cash to Service All of Our Indebtedness and May Be
Forced to Take Other Actions to Satisfy Our Obligations under Applicable Debt Instruments, Which May
Not Be Successful.

Our ability to make scheduled payments on or to reﬁnance our indebtedness obligations depends on our

ﬁnancial condition and operating performance, which are subject to prevailing economic and competitive conditions
and certain ﬁnancial, business and other factors beyond our control. We may not be able to maintain a level of
cash ﬂows from operating activities sufﬁcient to permit us to pay the principal, premium, if any, and interest on
our indebtedness.

FORM 10-K PART I

2016 ANNUAL REPORT

If our cash ﬂows and capital resources are insufﬁcient to fund debt service obligations, we may be forced to
reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or reﬁnance
indebtedness. Our ability to restructure or reﬁnance indebtedness will depend on the condition of the capital
markets and our ﬁnancial condition at such time. Any reﬁnancing of indebtedness could be at higher interest rates
and may require us to comply with more onerous covenants, which could further restrict business operations. The
terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition,
any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely
result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the
absence of sufﬁcient cash ﬂows and capital resources, we could face substantial liquidity problems and might be
required to dispose of material assets or operations to meet debt service and other obligations. Our Credit
Agreement and the indenture governing our outstanding senior notes currently restrict our ability to dispose of
assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions,
and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These
alternative measures may not be successful and may not permit us to meet scheduled debt service obligations,
which could have a material adverse effect on our ﬁnancial condition and results of operations.

We May Incur Additional Indebtedness, Which Could Reduce Our Financial Flexibility, Increase Interest
Expense and Adversely Impact Our Operations and Our Unit Costs.

At February 22, 2017, we had available borrowings of approximately $399.2 million under our Credit Agreement

(after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders
based primarily on the estimated value of our existing and future oil and natural gas reserves, but both we and
our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit
Agreement is secured by our interests in the majority of our oil and natural gas properties, and contains covenants
restricting our ability to incur additional indebtedness, sell assets, pay dividends and make certain investments.
Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a lower borrowing
base, we could be required to provide additional collateral satisfactory in nature and value to the lenders to increase
the borrowing base to an amount sufﬁcient to cover such excess or repay the deﬁcit in equal installments over
a period of six months. If we are required to do so, we may not have sufﬁcient funds to fully make such repayments.

In the future, subject to the restrictions in the indenture governing our outstanding senior notes and in other

instruments governing our other outstanding indebtedness (including our Credit Agreement), we may incur
signiﬁcant amounts of additional indebtedness, including under our Credit Agreement or through the issuance of
additional notes, in order to fund acquisitions, develop our properties or invest in certain exploration opportunities.
Interest rates on such future indebtedness may be higher than current levels, causing our ﬁnancing costs to
increase accordingly.

A high level of indebtedness could affect our operations in several ways, including the following:

(cid:85)

requiring a signiﬁcant portion of our cash ﬂows to be used for servicing our indebtedness;

increasing our vulnerability to general adverse economic and industry conditions;

(cid:85) placing us at a competitive disadvantage compared to our competitors that are less leveraged and,

therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us
from pursuing;

(cid:85)

restricting our ability to obtain additional ﬁnancing in the future for working capital, capital expenditures,
acquisitions and general corporate or other purposes; and

(cid:85)

increasing the risk that we may default on our debt obligations.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Our Credit Rating May Be Downgraded, Which Could Reduce Our Financial Flexibility, Increase Interest
Expense and Adversely Impact Our Operations.

As of February 22, 2017, our corporate credit rating from Standard & Poor’s Rating Services was “B” and our

corporate credit rating from Moody’s Investors Service was “B2.” We cannot assure you that our credit ratings
will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a
rating agency if, in its judgment, circumstances so warrant. Any future downgrade could increase the cost of
any indebtedness incurred in the future.

Any increase in our ﬁnancing costs resulting from a credit rating downgrade could adversely affect our ability

to obtain additional ﬁnancing in the future for working capital, capital expenditures, acquisitions and general
corporate or other purposes. If a credit rating downgrade were to occur at a time when we were experiencing
signiﬁcant working capital requirements or otherwise lacked liquidity, our results of operations could be
materially adversely affected.

Our Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May
Not Be Adequately Insured.

There are numerous operational hazards inherent in oil and natural gas exploration, development, production,

gathering and processing, including:

(cid:85) natural disasters;

(cid:85) adverse weather conditions;

(cid:85)

loss of drilling ﬂuid circulation;

(cid:85) blowouts where oil or natural gas ﬂows uncontrolled at a wellhead;

(cid:85) cratering or collapse of the formation;

(cid:85) pipe or cement leaks, failures or casing collapses;

(cid:85) damage to pipelines, processing plants and disposal wells and associated facilities;

(cid:85) ﬁres or explosions;

(cid:85)

releases of hazardous substances or other waste materials that cause environmental damage;

(cid:85) pressures or irregularities in formations; and

(cid:85) equipment failures or accidents.

In addition, there is an inherent risk of incurring signiﬁcant environmental costs and liabilities in the performance of

our operations and services, some of which may be material, due to our handling of petroleum hydrocarbons and
wastes, our emissions to air and water, the underground injection or other disposal of wastes, the use of hydraulic
fracturing ﬂuids and historical industry operations and waste disposal practices. Any of these or other similar
occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or
loss of human life, signiﬁcant damage to property, environmental pollution and substantial revenue losses. The
location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential
areas, commercial business centers and industrial sites, could signiﬁcantly increase the level of damages resulting
from these risks.

FORM 10-K PART I

2016 ANNUAL REPORT

Insurance against all operational risks is not available to us. We are not fully insured against all risks, including
development and completion risks that are generally not recoverable from third parties or insurance. Pollution and
environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe
that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore,
occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover,
insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms.
Changes in the insurance markets due to various factors may make it more difﬁcult for us to obtain certain types
of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would
otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover
certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses
and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have
a material adverse effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

Because Our Reserves and Production Are Concentrated in a Few Core Areas, Problems in Production and
Markets Relating to a Particular Area Could Have a Material Impact on Our Business.

Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties

in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the
Haynesville shale in Northwest Louisiana and East Texas. In 2015 and 2016, the vast majority of our capital
expenditures have been allocated to the Delaware Basin. As a result, for the year ended December 31, 2016,
approximately 57% of our total oil and natural gas production, including approximately 75% of our average daily oil
production, was attributable to our properties in the Delaware Basin and approximately 18% of our total oil
and natural gas production, including approximately 25% of our average daily oil production, was attributable to our
properties in the Eagle Ford shale. At December 31, 2016, approximately 75% of our total proved oil and natural
gas reserves were attributable to our properties in the Delaware Basin. We expect that a signiﬁcant portion of our
operations in 2017 will be in the Delaware Basin.

The industry focus on the Delaware Basin may adversely impact our ability to transport and process our oil and

natural gas production due to signiﬁcant competition for gathering systems, pipelines, processing facilities and
oil and condensate trucking operations. For example, infrastructure constraints have in the past required, and may
in the future require, us to ﬂare natural gas occasionally, decreasing the volumes sold from our wells. Due to the
concentration of our operations, we may be disproportionately exposed to the impact of delays or interruptions of
production from our wells in our operating areas caused by transportation capacity constraints or interruptions,
curtailment of production, availability of equipment, facilities, personnel or services, signiﬁcant governmental
regulation, natural disasters, adverse weather conditions or plant closures for scheduled maintenance.

Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical

storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and
equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely
manner. For example, in recent years the Delaware Basin has experienced periods of severe winter weather that
impacted many operators. In particular, the weather conditions and freezing temperatures have resulted in power
outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. In
recent years, certain areas of the Delaware Basin have also experienced periods of severe ﬂooding that impacted
our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating
production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly face
these and other challenges posed by severe weather.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of

the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they
might have on other companies that have a more diversiﬁed portfolio of properties. For example, our operations in
the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities
and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material
adverse effect on our ﬁnancial condition, results of operations and cash ﬂows.

The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and
Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to
Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which
Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.

Shortages or the high cost of drilling rigs, completion equipment and services, personnel or supplies, including
sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States
increases, associated costs typically also increase, including those costs related to drilling rigs, equipment,
supplies, including sand and other proppants, and personnel and the services and products of other industry vendors.
These costs may increase, and necessary equipment, supplies and services may become unavailable to us at
economical prices. Should this increase in costs occur, we may delay drilling activities, which may limit our ability to
establish and replace reserves, or we may incur these higher costs, which may negatively affect our business,
ﬁnancial condition, results of operations and cash ﬂows. In addition, should low oil or natural gas prices continue or
should oil and natural gas prices decline further, third-party service providers may face ﬁnancial difﬁculties and be
unable to provide services. A reduction in the number of service providers available to us may negatively impact our
ability to retain qualiﬁed service providers, or obtain such services at costs acceptable to us.

In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing
equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear
of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas ﬁelds characterized
by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew
shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews
were to decrease, higher costs or delays in procuring these services could result, which could adversely affect our
business, ﬁnancial condition, results of operations and cash ﬂows.

If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing
Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable
Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial
Quantities Could Be Impaired.

We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain
sufﬁcient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing,
could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced
severe drought. As a result, we may experience difﬁculty in securing the necessary volumes of water for our
operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on
our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited
to, produced water, drilling ﬂuids and other wastes associated with the exploration, development and production of
oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the
withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could
increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot
be predicted, all of which could have an adverse effect on our business, ﬁnancial condition, results of operations
and cash ﬂows.

FORM 10-K PART I

2016 ANNUAL REPORT

Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline,
Which Would Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.

The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil

and natural gas reserves and production and, therefore, our income and cash ﬂow, are highly dependent on our
success in efﬁciently developing and exploiting our current reserves and economically ﬁnding or acquiring additional
oil and natural gas producing properties. We are currently focusing primarily on increasing our production and
reserves from the Delaware Basin, an area in which our competitors have been active. As a result of this activity, we
may have difﬁculty expanding our current production or acquiring new properties in this area and may experience
such difﬁculty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may
no longer be economic, and it will become more difﬁcult to raise the capital necessary to ﬁnance expansion
activities. If we are unable to replace our current and future production, our reserves will decrease, and our business,
ﬁnancial condition, results of operations and cash ﬂows would be adversely affected.

Our Oil and Natural Gas Reserves Are Estimated and May Not Reﬂect the Actual Volumes of Oil and
Natural Gas We Will Recover, and Signiﬁcant Inaccuracies in These Reserves Estimates or Underlying
Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves.

The process of estimating accumulations of oil and natural gas is complex and inexact, due to numerous

inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and
production data. The extent, quality and reliability of this technical data can vary. This process also requires certain
economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses,
capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of:

(cid:85)

the quality and quantity of available data;

the interpretation of that data;

the judgment of the persons preparing the estimate; and

the accuracy of the assumptions used.

The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of

production history. Due to the limited production history of many of our properties, the estimates of future
production associated with these properties may be subject to greater variance to actual production than would
be the case with properties having a longer production history. As our wells produce over time and more data
becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be
adjusted to reﬂect new information based upon our actual production history, results of exploration and development,
prevailing oil and natural gas prices and other factors.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating

expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that
future production declines in our wells may be greater than we have estimated. Any signiﬁcant variance from our
estimates could materially affect the quantities and present value of our reserves.

The Calculated Present Value of Future Net Revenues from Our Proved Oil and Natural Gas Reserves Will
Not Necessarily Be the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves.

It should not be assumed that the present value of future net cash ﬂows included in this Annual Report is the
current market value of our estimated proved oil and natural gas reserves. As required by SEC rules and regulations,
the estimated discounted future net cash ﬂows from proved oil and natural gas reserves are based on current
costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average
of ﬁrst-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding

FORM 10-K PART I

MATADOR RESOURCES COMPANY

the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs
used for these estimates and will be affected by factors such as:

(cid:85) actual prices we receive for oil and natural gas;

(cid:85) actual costs and timing of development and production expenditures;

(cid:85)

the amount and timing of actual production; and

(cid:85) changes in governmental regulations or taxation.

In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for

reporting purposes under U.S. generally accepted accounting principles, or GAAP, is not necessarily the most
appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our
business and the oil and natural gas industry in general.

Approximately 59% of Our Total Proved Reserves at December 31, 2016 Consisted of Undeveloped and
Developed Non-Producing Reserves, and Those Reserves May Not Ultimately Be Developed or Produced.

At December 31, 2016, approximately 59% of our total proved reserves were undeveloped and less than 1% of

our total proved reserves were developed non-producing. Our undeveloped and/or developed non-producing
reserves may never be developed or produced or such reserves may not be developed or produced within the time
periods we have projected or at the costs we have estimated. Delays in the development of our reserves or
increases in costs to drill and develop such reserves would reduce the present value of our estimated proved
undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming
uneconomical and reducing our total proved reserves. In addition, delays in the development of reserves or
declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have
to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused
by the reclassiﬁcation of undeveloped or developed non-producing reserves could materially affect our business,
ﬁnancial condition, results of operations and cash ﬂows.

Our Identiﬁed Drilling Locations Are Scheduled over Several Years, Making Them Susceptible
to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.

Our management team has identiﬁed and scheduled drilling locations in our operating areas over a multi-year
period. Our ability to drill and develop these locations depends on a number of factors, including oil and natural gas
prices, assessment of risks, costs, drilling results, reservoir heterogeneities, the availability of equipment and
capital, approval by regulators, lease terms and seasonal conditions. The ﬁnal determination on whether to drill any
of these locations will be dependent upon the factors described elsewhere in this Annual Report as well as, to some
degree, the results of our drilling activities with respect to our established drilling locations. Because of these
uncertainties, we do not know if the drilling locations we have identiﬁed will be drilled within our expected timeframe,
or at all, or if we will be able to economically produce hydrocarbons from these or any other potential drilling
locations. Our actual drilling activities may be materially different from our current expectations, which could adversely
affect our business, ﬁnancial condition, results of operations and cash ﬂows.

Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases That Will Expire over the Next
Several Years Unless Production Is Established on Units Containing the Acreage.

At December 31, 2016, we had leasehold interests in approximately 44,975 net acres across all of our areas of

interest that are not currently held by production and are subject to leases with primary or renewed terms that
expire prior to 2020. Unless we establish and maintain production, generally in paying quantities, on units containing
these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases

FORM 10-K PART I

2016 ANNUAL REPORT

may increase signiﬁcantly, and we may not be able to renew such leases on commercially reasonable terms or at
all. In addition, on certain portions of our acreage, third-party leases may have been taken and could become
immediately effective if our leases expire. If our leases expire or we are unable to renew such leases, we will lose
our right to develop the related properties. As such, our actual drilling activities may materially differ from our current
expectations, which could adversely affect our business, ﬁnancial condition, results of operations and cash ﬂows.

The 2-D and 3-D Seismic Data and Other Advanced Technologies We Use Cannot Eliminate Exploration
Risk, Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and Adversely Affect
Our Results of Operations and Cash Flows.

We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities
where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon
indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically
producible. We could incur losses by drilling unproductive wells based on these technologies. Furthermore, seismic
and geological data can be expensive to license or obtain and we may not be able to license or obtain such data
at an acceptable cost. Poor results from our exploration activities could limit our ability to replace and grow reserves
and adversely affect our business, ﬁnancial condition, results of operations and cash ﬂows.

Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difﬁcult for Us to Acquire
Properties, Market Oil and Natural Gas, Provide Midstream Services and Secure Trained Personnel.

Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to ﬁnd

and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to
consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas
and securing trained personnel. Similarly, our midstream business, and particularly the success of the Joint Venture,
depends in part on our ability to compete with other midstream service companies to attract third-party customers
to our midstream facilities. Also, there is substantial competition for capital available for investment in the oil
and natural gas industry. Many of our competitors possess and employ ﬁnancial, technical and personnel resources
substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas
properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and
prospects than our ﬁnancial or personnel resources permit. In addition, other companies may be able to offer better
compensation packages to attract and retain qualiﬁed personnel than we are able to offer. The cost to attract
and retain qualiﬁed personnel has increased in recent years due to competition and may increase substantially in
the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing
reserves, developing midstream assets, marketing hydrocarbons, attracting and retaining quality personnel and
raising additional capital, which could have a material adverse effect on our business, ﬁnancial condition, results of
operations and cash ﬂows.

Our Competitors May Use Superior Technology and Data Resources That We May Be Unable to Afford or
That Would Require a Costly Investment by Us in Order to Compete with Them More Effectively.

Our industry is subject to rapid and signiﬁcant advancements in technology, including the introduction of new
products, equipment and services using new technologies and databases. As our competitors use or develop new
technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to
implement new technologies at a substantial cost. In addition, many of our competitors will have greater ﬁnancial,
technical and personnel resources that allow them to enjoy technological advantages and may in the future allow
them to implement new technologies before we can. We cannot be certain that we will be able to implement
technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use
or that we may implement in the future may become obsolete, and our operations may be adversely affected.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Strategic Relationships upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability
to Conduct Our Operations.

Our ability to explore, develop and produce oil and natural gas resources successfully, acquire oil and natural
gas interests and acreage and conduct our midstream activities depends on our developing and maintaining close
working relationships with industry participants and on our ability to select and evaluate suitable acquisition
opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our
ability to grow may be impaired.

To develop our business, we endeavor to use the business relationships of our management, board and special
board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other
oil and natural gas companies and service companies, including those that supply equipment and other resources
that we expect to use in our business, as well as midstream companies and certain ﬁnancial institutions. We may
not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In
addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake
activities we would not otherwise be inclined to incur in order to fulﬁll our obligations to these partners or
maintain our relationships. If our strategic relationships are not established or maintained, our business prospects
may be limited, which could diminish our ability to conduct our operations.

The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and
Transportation Facilities, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing
and Transportation Arrangements Could Have a Material Adverse Effect on Our Revenue.

The unavailability of satisfactory oil, natural gas and natural gas liquids gathering, processing and transportation
arrangements may hinder our access to oil, natural gas and natural gas liquids markets or delay production from our
wells. The availability of a ready market for our oil, natural gas and natural gas liquids production depends on a
number of factors, including the demand for, and supply of, oil, natural gas and natural gas liquids and the proximity
of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part
on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking
operations. Such systems and operations include those of the Joint Venture, as well as other systems and
operations owned and operated by third parties. The continuing operation of, and our continuing access to, third-party
systems and operations is outside our control. Regardless of who operates the midstream systems or operations
upon which we rely, our failure to obtain these services on acceptable terms could materially harm our business.
In addition, certain of these gathering systems, pipelines and processing facilities, particularly in the Delaware Basin,
may be outdated or in need of repair and subject to higher rates of line loss, failure and breakdown. Furthermore,
such facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced
operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due
to insufﬁcient capacity or because of damage from severe weather conditions or other operational issues.

We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines,

gathering systems, processing facilities or trucking capacity. If that were to occur, we would be unable to realize
revenue from those wells until production arrangements were made to deliver our production to market. Furthermore,
if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest
owners in order to maintain our leases. In addition, if we are unable to market our production we may be required to
ﬂare natural gas occasionally, which would decrease the volumes sold from our wells.

FORM 10-K PART I

2016 ANNUAL REPORT

The disruption of our or third-party facilities due to maintenance, weather or other factors could negatively impact

our ability to market and deliver our oil, natural gas and natural gas liquids. If our costs to access and transport on
these pipelines signiﬁcantly increase, our proﬁtability could be reduced. Third parties control when or if their facilities
are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing
interruptions and capacity and infrastructure constraints associated with natural gas production, which has, among
other things, required us to ﬂare natural gas occasionally. While we have entered into natural gas processing and
transportation agreements covering the anticipated natural gas production from a signiﬁcant portion of our Delaware
Basin acreage in Southeast New Mexico and West Texas and our Eagle Ford shale acreage in South Texas, no
assurance can be given that these agreements will alleviate these issues completely, and we may be required to
pay deﬁciency payments under such agreements if we do not meet the gathering, disposal or processing
commitments, as applicable. We may experience similar interruptions and processing capacity constraints as we
continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in
2017. If we were required to shut in our production or ﬂare our natural gas for long periods of time due to pipeline
interruptions or lack of processing facilities or capacity of these facilities, it could have a material adverse effect
on our business, ﬁnancial condition, results of operations and cash ﬂows.

Financial Difﬁculties Encountered by Our Oil and Natural Gas Purchasers, Third-Party Operators or
Other Third Parties Could Decrease Our Cash Flows from Operations and Adversely Affect the Exploration
and Development of Our Prospects and Assets.

We derive most of our revenues from the sale of our oil, natural gas and natural gas liquids to unafﬁliated

third-party purchasers, independent marketing companies and midstream companies. We are also subject to credit
risk due to the concentration of our oil and natural gas receivables with several signiﬁcant customers. We cannot
predict the extent to which counterparties’ businesses would be impacted if oil and natural gas prices decline, such
prices remain depressed for a sustained period of time or other conditions in our industry were to deteriorate. Any
delays in payments from our purchasers caused by ﬁnancial problems encountered by them will have an immediate
negative effect on our results of operations and cash ﬂows.

Liquidity and cash ﬂow problems encountered by our working interest co-owners or the third-party operators of
our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working
interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due.
In the case of a farmout party, we would have to ﬁnd a new farmout party or obtain alternative funding in order to
complete the exploration and development of the prospects subject to a farmout agreement. In the case of a
working interest owner, we could be required to pay the working interest owner’s share of the project costs. If we
are not able to obtain the capital necessary to fund either of these contingencies or ﬁnd a new farmout party, our
results of operations and cash ﬂows could be negatively affected.

Our Natural Gas Processing Operations Are Subject to Operational Risks, Which Could Result in Signiﬁcant
Damages and the Loss of Revenue.

The Joint Venture owns, and we operate, the Black River Processing Plant. There are signiﬁcant risks associated

with the operation of cryogenic natural gas processing plants. Natural gas and natural gas liquids are volatile and
explosive and may include carcinogens. Damage to or improper operation of a cryogenic natural gas processing
plant could result in an explosion or the discharge of toxic gases, which could result in signiﬁcant damage claims,
interrupt a revenue source and prevent us from processing some or all of the natural gas produced from our
wells located in the Rustler Breaks asset area. Furthermore, if we were unable to process such natural gas, we
may be forced to ﬂare natural gas from, or shut in, the affected wells for an indeﬁnite period of time.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

We Have Entered into Certain Long-Term Contracts That Require Us to Pay Fees to Our Service Providers
Based on Minimum Volumes Regardless of Actual Volume Throughput and That May Limit Our Ability to
Use Other Service Providers.

In connection with the sale of the Loving County Processing System in October 2015, we entered into a 15-year

ﬁxed-fee natural gas gathering and processing agreement covering the anticipated natural gas production from a
signiﬁcant portion of our acreage in the Wolf asset area in the Delaware Basin (the “Wolf Gathering Agreement”).
In addition, in connection with the formation of the Joint Venture, we entered into certain 15-year ﬁxed-fee natural
gas, oil and salt water gathering agreements and salt water disposal agreements covering the Rustler Breaks and Wolf
asset areas and a natural gas processing agreement covering the Rustler Breaks asset area (collectively, the “Joint
Venture Agreements”). We are also subject to a ﬁrm natural gas processing and transportation agreement covering
the anticipated natural gas production from a signiﬁcant portion of our Eagle Ford shale acreage in South Texas,
which agreement expires in September 2017. In each of these agreements we have provided certain minimum
volume commitments. Lower commodity prices may lead to reductions in our drilling program, which may result in
insufﬁcient production to fulﬁll our obligations under these agreements. These agreements obligate us to pay fees
on minimum volumes to our service providers (including the Joint Venture) regardless of actual throughput. As of
December 31, 2016, our long-term contractual obligations under agreements with minimum volume commitments
totaled approximately $12.9 million over the term of the agreements (excluding the Joint Venture Agreements,
which were entered into in 2017). If we have insufﬁcient production to meet the minimum volumes, our cash ﬂow
from operations will be reduced, which may require us to reduce or delay our planned investments and capital
expenditures or seek alternative means of ﬁnancing, all of which may have a material adverse effect on our results
of operations.

Pursuant to the Wolf Gathering Agreement and the Joint Venture Agreements, we have dedicated our current

and future leasehold interests in the Wolf and Rustler Breaks asset areas to EnLink or the Joint Venture, as
applicable. As a result, we will be limited in our ability to use other gathering, processing, disposal and transportation
service providers in the Wolf and Rustler Breaks asset areas, even if such service providers are able to offer us
more favorable pricing or more efﬁcient service.

Gathering, Processing and Transportation Services Are Subject to Complex Federal, State and Other Laws
that Could Adversely Affect the Cost, Manner or Feasibility of Conducting Our Business.

The operations of our midstream business, including the Joint Venture, and the operations of the third parties on

whom we rely for gathering, processing and transportation services, are subject to complex and stringent laws
and regulations that require obtaining and maintaining numerous permits, approvals and certiﬁcations from various
federal, state and local government authorities. Substantial costs may be incurred in order to comply with existing
laws and regulations. If existing laws and regulations governing such services are revised or reinterpreted, or if new
laws and regulations become applicable to operations, these changes may affect the costs that we pay for such
services or the results of our midstream business, including the Joint Venture. Similarly, a failure to comply with
such laws and regulations by us or the parties on whom we rely could have a material adverse effect on our
business, ﬁnancial condition, results of operations and cash ﬂows. See “Business — Regulation.”

We Have Limited Control over Activities on Properties We Do Not Operate.

We are not the operator on some of our properties, particularly in the Haynesville shale. As a result of our sale

of certain assets to Chesapeake in 2008, we do not operate one of our most signiﬁcant natural gas assets in the
Haynesville shale. We also have other non-operated acreage positions in Northwest Louisiana, South Texas, Southeast
New Mexico and West Texas. Because we are not the operator for these properties, our ability to exercise inﬂuence
over the operations of these properties or their associated costs is limited. Our dependence on the operators and

FORM 10-K PART I

2016 ANNUAL REPORT

other working interest owners of these projects and our limited ability to inﬂuence operations and associated costs,
or control the risks, could materially and adversely affect the drilling results, reserves and future cash ﬂows from
these properties. The success and timing of our drilling and development activities on properties operated by others
therefore depends upon a number of factors, including:

(cid:85)

timing and amount of capital expenditures;

the operator’s expertise and ﬁnancial resources;

the rate of production of reserves, if any;

(cid:85) approval of other participants in drilling wells; and

(cid:85) selection and implementation or execution of technology.

In areas where we do not have the right to propose the drilling of wells, we may have limited inﬂuence on when,

how and at what pace our properties in those areas are developed. Further, the operators of those properties may
experience ﬁnancial problems in the future or may sell their rights to another operator not of our choosing, both
of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the
operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these
properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production
and associated revenues from these properties until the operator elects to return them to production.

We Conduct a Portion of Our Operations through Joint Ventures, Which Subjects Us to Additional Risks
That Could Have a Material Adverse Effect on the Success of These Operations, Our Financial Position, Results
of Operations or Cash Flows.

We own and operate substantially all of our midstream assets in the Delaware Basin through the Joint Venture,

and we may enter into other joint venture arrangements in the future. The nature of a joint venture requires us to
share a portion of control with unafﬁliated third parties. If our joint venture partners do not fulﬁll their contractual and
other obligations, the affected joint venture may be unable to operate according to its business plan, and we may
be required to increase our level of ﬁnancial commitment. If we do not timely meet our ﬁnancial commitments or
otherwise comply with our joint venture agreements, our ownership of and rights with respect to the applicable
joint venture may be reduced or otherwise adversely affected. Furthermore, there can be no assurance that any joint
venture will be successful or generate cash ﬂows at the level we have anticipated, or at all. Differences in views
among joint venture participants could also result in delays in business decisions or otherwise, failures to agree on
major issues, operational inefﬁciencies and impasses, litigation or other issues. We provide management functions
for the Joint Venture and may provide such services for future joint venture arrangements, which may require
additional time and attention of management or require us to hire or contract additional personnel. Third parties may
also seek to hold us liable for the joint ventures’ liabilities. These issues or any other difﬁculties that cause a joint
venture to deviate from its original business plan could have a material adverse effect on our ﬁnancial condition,
results of operations and cash ﬂows.

We Do Not Own All of the Land on Which Our Midstream Assets Are Located, Which Could Disrupt
Our Operations.

We do not own all of the land on which our midstream assets are located, and we are therefore subject to the
possibility of more onerous terms and/or increased costs or royalties to retain necessary land use if we do not have
valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights
to land owned by third parties and governmental agencies for a speciﬁc period of time. Our loss of these rights,
through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the
affected land or ﬁnd alternative locations for our operations at increased costs, each of which could have a material
adverse effect on our business, ﬁnancial condition, results of operations and cash ﬂows.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Construction of Midstream Projects Subjects Us to Risks of Construction Delays, Cost Over-Runs,
Limitations on Our Growth and Negative Effects on Our Financial Condition, Results of Operations, Cash
Flows and Liquidity.

From time-to-time we, through the Joint Venture or otherwise, plan and construct midstream projects, some of

which will take a number of months before commercial operation, such as the Joint Venture’s expansion of the
Black River Processing Plant or the drilling of additional salt water disposal wells and construction of related facilities.
These projects are complex and subject to a number of factors beyond our control, including delays from third-party
landowners, the permitting process, complying with laws, unavailability of materials, labor disruptions, environmental
hazards, ﬁnancing, accidents, weather and other factors. Any delay in the completion of these projects could have
a material adverse effect on our business, results of operations, liquidity and ﬁnancial condition. The construction of
salt water disposal facilities, pipelines and gathering and processing facilities requires the expenditure of signiﬁcant
amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these
development projects is very complex and subject to variables that can signiﬁcantly increase expected costs.
Should the actual costs of these projects exceed our estimates, our liquidity and ﬁnancial condition could be
adversely affected. This level of development activity requires signiﬁcant effort from our management and technical
personnel and places additional requirements on our ﬁnancial resources and internal ﬁnancial controls. We may not
have the ability to attract and/or retain the necessary number of personnel with the skills required to bring
complicated projects to successful conclusions.

A Component of Our Growth May Come through Acquisitions, and Our Failure to Identify or Complete
Future Acquisitions Successfully Could Reduce Our Earnings and Hamper Our Growth.

We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider
economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition
for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The pursuit and
completion of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity
ﬁnancing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue
to invest in operations and ﬁnancial and management information systems and to attract, retain, motivate and
effectively manage our employees. In addition, if we are not successful in identifying and acquiring properties, our
earnings could be reduced and our growth could be restricted.

In addition, we may be unable to successfully integrate potential acquisitions into our existing operations.

The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions
and current operations, and could negatively impact our results of operations and growth potential. Members of
our senior management team may be required to devote considerable amounts of time to the integration process,
which will decrease the time they will have to manage our business.

Furthermore, our decision to acquire properties that are substantially different in operating or geologic

characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in
such areas. Our ﬁnancial condition, results of operations and cash ﬂows may ﬂuctuate signiﬁcantly from period
to period as a result of the completion of signiﬁcant acquisitions during particular periods.

We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or
increase substantially our capitalization to ﬁnance these acquisitions through the use of cash on hand, the issuance
of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil
and natural gas producing assets or acreage, the borrowing of funds or otherwise. Our Credit Agreement and the
indenture governing our outstanding senior notes include covenants limiting our ability to incur additional debt.
If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders
would suffer dilution of their interests.

FORM 10-K PART I

2016 ANNUAL REPORT

We May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know About or
That We Did Not Assess Correctly, and, as a Result, We Could Be Subject to Liabilities That Could Adversely
Affect Our Results of Operations.

Before acquiring oil and natural gas properties, we assess the potential reserves, future oil and natural gas prices,

operating costs, potential environmental liabilities and other factors relating to the properties. However, our review
involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not
discover all existing or potential problems associated with the properties we buy. We may not become sufﬁciently
familiar with the properties to assess fully their deﬁciencies and capabilities. We do not generally perform
inspections on every well or property, and we may not be able to observe mechanical and environmental problems
even when we conduct an inspection. The seller may not be willing or ﬁnancially able to give us contractual
protection against any identiﬁed problems, and we may decide to assume environmental and other liabilities in
connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or
that we did not assess correctly, our ﬁnancial condition, results of operations and cash ﬂows could be adversely
affected as we settle claims and incur cleanup costs related to these liabilities.

We May Incur Losses or Costs as a Result of Title Deﬁciencies in the Properties in Which We Invest.

If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease
has been purchased in error from a person who is not the mineral interest owner or if the property has other title
deﬁciencies, our interest would likely be worth less than what we paid or may be worthless. In such an instance,
all or part of the amount paid for such oil and natural gas lease as well as all or part of any royalties paid pursuant to
the terms of the lease prior to the discovery of the title defect would be lost.

It is not our practice in all acquisitions of oil and natural gas leases, or undivided interests in oil and natural gas
leases, to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under
lease or already placed under lease. Rather, in certain acquisitions we rely upon the judgment of oil and natural
gas lease brokers and/or landmen who perform the ﬁeld work by examining records in the appropriate governmental
ofﬁce before attempting to acquire a lease on a speciﬁc mineral interest.

Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the
well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure
there are no obvious deﬁciencies in title to the well. Frequently, as a result of such examinations, certain curative
work must be done to correct deﬁciencies in the marketability of the title, and such title review and curative work
entails expense, which may be signiﬁcant and difﬁcult to accurately predict. Our failure to cure any title defects may
adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss
from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than
developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in
which we hold an interest, we will suffer a ﬁnancial loss which could adversely affect our ﬁnancial condition, results
of operations and cash ﬂows.

We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules
and These Write-Downs Could Adversely Affect Our Financial Condition.

There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when

oil or natural gas prices are low or are declining. In addition, non-cash write-downs may occur if we have:

(cid:85) downward adjustments to our estimated proved reserves;

(cid:85)

increases in our estimates of development costs; or

(cid:85) deterioration in our exploration and development results.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules.
Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may
not exceed a cost center ceiling that is calculated by determining the present value, based on constant prices and
costs projected forward from a single point in time, of estimated future after-tax net cash ﬂows from proved reserves,
discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income
taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which
the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods.

During the ﬁrst and second and quarters of 2016, our net capitalized costs less related deferred income taxes
exceeded the full-cost ceiling. As a result, we recorded impairment charges totaling $158.6 million, exclusive of tax
effect, to our net capitalized costs for the year ended December 31, 2016. For further discussion of the full-cost
ceiling impairment at December 31, 2016, see “Management’s Discussion and Analysis of Financial Condition and
Results of Operations—Expenses.” A write-down does not affect net cash ﬂows from operating activities, liquidity
or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and
shareholders’ equity, and could lower the value of our common stock.

Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in
Financial Losses.

To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily

“costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us
with downside price protection through the purchase of a put option which is ﬁnanced through the sale of a call
option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are
initially “costless” to us. In the case of a costless collar, the put option and the call option have different ﬁxed price
components. In a swap contract, a ﬂoating price is exchanged for a ﬁxed price over the speciﬁed period, providing
downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or
a ﬁxed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash ﬂows.
These transactions limit our potential gains if oil, natural gas or natural gas liquids prices rise above the maximum
price established by the call option and may offer protection if prices fall below the minimum price established by
the put option only to the extent of the volumes then hedged.

In addition, hedging transactions may expose us to the risk of ﬁnancial loss in certain other circumstances,

including instances in which our production is less than expected or the counterparties to our put and call option or
swap contracts fail to perform under the contracts. Disruptions in the ﬁnancial markets could lead to sudden
changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We
are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts
with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending
upon market conditions.

Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have
been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difﬁcult
and depend on market conditions and our forecast of future production and oil, natural gas and natural gas liquids
prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future
that differ from those that we have used in the past, and neither the continued application of our current strategies
nor our use of different hedging strategies may be successful. As of February 22, 2017, we had approximately
70% and 50% of our estimated remaining 2017 oil and natural gas production, respectively, hedged. We currently
have no hedges in place for natural gas liquids and no hedges in place for natural gas beyond 2017; however, we
have a portion of our anticipated oil volumes hedged in 2018.

FORM 10-K PART I

2016 ANNUAL REPORT

An Increase in the Differential between the NYMEX or Other Benchmark Prices of Oil and Natural Gas
and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial
Condition, Results of Operations and Cash Flows.

The prices that we receive for our oil and natural gas production sometimes reﬂect a discount to the relevant

benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the
benchmark prices and the prices we receive is called a differential. Increases in the differential between the
benchmark prices for oil and natural gas and the wellhead prices we receive could adversely affect our business,
ﬁnancial condition, results of operations and cash ﬂows. We do not have, and may not have in the future, any
derivative contracts covering the amount of the basis differentials we experience with respect to our production.
As such, we will be exposed to any increase in such differentials.

We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which
Could Require Signiﬁcant Expenditures.

The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas in

the United States are subject to many federal, state and local laws, rules and regulations, including complex
environmental laws and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports
concerning operations, the spacing of wells, unitization and pooling of properties, taxation and environmental
matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may
be required to make large expenditures that could materially adversely affect our ﬁnancial condition, results
of operations and cash ﬂows. In addition to expenditures required in order for us to comply with such laws and
regulations, these expenditures could also include payments for:

(cid:85) personal injuries;

(cid:85) property damage;

(cid:85) containment and clean-up of oil and other spills;

(cid:85) management and disposal of hazardous materials;

(cid:85)

remediation, clean-up costs and natural resource damages; and

(cid:85) other environmental damages.

We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure

to comply with these laws and regulations also may result in the suspension or termination of our operations and
subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or
other remedial obligations. Laws, rules and regulations protecting the environment have changed frequently and
the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability
on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault.
We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or
regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced
by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which
our wells are drilled or facilities are located, or the owners of properties adjacent to or in close proximity to those
properties, may also pursue legal actions against us based on alleged non-compliance with certain of these laws,
rules and regulations.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Part of the regulatory environment in which we operate includes, in some cases, federal requirements for

obtaining environmental assessments, environmental impact statements and/or plans of development before
commencing exploration and production activities. Oil and natural gas operations in certain of our operating areas
can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various
wildlife. The designation of previously unprotected species as threatened or endangered species could prohibit
drilling in certain of our operating areas, cause us to incur increased costs arising from species protection measures
or result in limitations on our exploration and production activities, each of which could have an adverse impact on
our ability to develop and produce our reserves.

We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have
Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and
Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely
Affect Our Business, Financial Condition, Results of Operations and Cash Flows.

The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural

Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently

available to oil and natural gas exploration and production companies. Such changes include, but are not limited to,
(i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination
of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain
U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and
geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within
the United States. The passage of any legislation or any other similar change in U.S. federal income tax law
could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and
production activities and could negatively impact our ﬁnancial condition, results of operations and cash ﬂows.

Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in
Increased Costs and Additional Operating Restrictions or Delays.

Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure

into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete
wells in order to produce oil, natural gas and natural gas liquids from formations such as the Wolfcamp and Bone
Spring plays, the Eagle Ford shale and the Haynesville shale, where we focus our operations. The EPA released
the ﬁnal results of its comprehensive research study on the potential adverse impacts that hydraulic fracturing may
have on drinking water resources in December 2016. The EPA concluded that hydraulic fracturing activities can
impact drinking water resources under certain circumstances, including large volume spills and inadequate mechanical
integrity of wells. The results of the EPA’s study could spur action towards federal legislation and regulation of
hydraulic fracturing or similar production operations. In past sessions, Congress has considered, but did not pass,
legislation to amend the SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations
(other than operations using ﬂuids containing diesel) and to require reporting and disclosure of chemicals used by oil
and natural gas companies in the hydraulic fracturing process. The EPA has issued SDWA permitting guidance
for hydraulic fracturing operations involving the use of diesel fuel in fracturing ﬂuids in those states where the EPA is
the permitting authority. Also at the federal level, the BLM issued ﬁnal rules to regulate hydraulic fracturing on
federal lands in March 2015, although these rules were struck down by a federal court in Wyoming in June 2016.
An appeal of the decision is pending.

FORM 10-K PART I

2016 ANNUAL REPORT

In addition, a number of states and local regulatory authorities are considering or have implemented more
stringent regulatory requirements applicable to hydraulic fracturing, including bans or moratoria on drilling that
effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar
operations. For example, in December 2014, New York announced a moratorium on high volume fracturing activities
combined with horizontal drilling following the issuance of a study regarding the safety of hydraulic fracturing.
Certain communities in Colorado have also enacted bans on hydraulic fracturing. These actions are the subject of
legal challenges. Texas, New Mexico and Wyoming have adopted regulations that require the disclosure of
information regarding the substances used in the hydraulic fracturing process. Moreover, in light of concerns about
seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are
also considering additional requirements related to seismic safety for hydraulic fracturing activities. A 2015 U.S.
Geological Survey report identiﬁed areas of increased rates of induced seismicity that could be attributed to ﬂuid
injection or oil and natural gas extraction.

The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting

or prohibiting, the hydraulic fracturing process could make it more difﬁcult to complete oil and natural gas wells in
unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal
legislation or regulatory initiatives by the EPA, hydraulic fracturing activities could become subject to additional
permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely
affect our business and results of operations.

Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating
Costs and Reduced Demand for the Oil, Natural Gas and Natural Gas Liquids We Produce while the Physical
Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Signiﬁcant Costs in
Preparing for or Responding to Those Effects.

The EPA has published its ﬁnal ﬁndings that emissions of carbon dioxide, methane and other greenhouse gases

present an endangerment to public health and welfare because emissions of such gases are, according to the
EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Accordingly, the EPA has
adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources under the
Prevention of Signiﬁcant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered
approach to this permitting, with the largest sources ﬁrst subject to permitting. In addition, monitoring of
greenhouse gas emissions from petroleum and natural gas systems commenced on January 1, 2011, with the ﬁrst
annual reports required to be ﬁled in 2012. In October 2015, the EPA ﬁnalized rules that added new sources to
the scope of the greenhouse gas monitoring and reporting requirements. These new sources include gathering and
boosting facilities as well as completions and workovers from hydraulically fractured oil and natural gas wells. The
revisions also include the addition of well identiﬁcation reporting requirements for certain facilities. There were
attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass.
Further, various states have considered or adopted legislation that seeks to control or reduce emissions of
greenhouse gases from a wide range of sources. Finally, in December 2015, the United States joined the international
community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change
in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the
average global temperature and to conserve and enhance sinks and reservoirs of greenhouse gases. The Paris
Agreement, if ratiﬁed, establishes a framework for the parties to cooperate and report actions to reduce greenhouse
gas emissions. Any future international agreements, federal or state laws or implementing regulations that may
be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased
operating costs, adversely affecting our proﬁts, and could adversely affect demand for the oil and natural gas we
produce, depressing the prices we receive for oil and natural gas.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have
an effect on the severity of weather (including hurricanes and ﬂoods), sea levels, the arability of farmland and water
availability and quality. If such effects were to occur, there is the potential for our exploration and production
operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful
winds or rising waters in low-lying areas, disruption of our production, less efﬁcient or non-routine operating
practices necessitated by climate effects and increased costs for insurance coverages in the aftermath of such
effects. Signiﬁcant physical effects of climate change could also have an indirect effect on our ﬁnancing and
operations by disrupting the transportation or process-related services provided by us or other midstream companies,
service companies or suppliers with whom we have a business relationship. We may not be able to recover
through insurance some or any of the damages, losses or costs that may result from potential physical effects of
climate change. In addition, our hydraulic fracturing operations require large amounts of water. See “—If We Are
Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to
Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to
Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired.” Should climate change
or other drought conditions occur, our ability to obtain water of a sufﬁcient quality and quantity could be impacted
and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly.

New Regulations on All Emissions from Our Operations Could Cause Us to Incur Signiﬁcant Costs.

On April 17, 2012, the EPA issued ﬁnal rules to subject oil and natural gas operations to regulation under the

New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants,
or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs.
The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells, compressors,
controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. Further, in
May 2016, the EPA issued ﬁnal NSPS governing methane emissions from the oil and natural gas industry as well as
source determination standards for determining when oil and natural gas sources should be aggregated for CAA
permitting and compliance purposes. The NSPS for methane extends the 2012 NSPS to completions of hydraulically
fractured oil and natural gas wells, equipment leaks, pneumatic pumps and natural gas compressors. These rules
have required changes to our operations, including the installation of new equipment to control emissions. The EPA
has also announced that it intends to impose methane emission standards for existing sources and has issued
information collection requests for oil and natural gas facilities. In November 2016, the Department of the Interior
issued ﬁnal rules relating to the venting, ﬂaring and leaking of natural gas by oil and natural gas producers who
operate on federal and Indian lands. The rules limit routine ﬂaring of natural gas, require the payment of royalties on
avoidable natural gas losses and require plans or programs relating to natural gas capture and leak detection and
repair. These rules are expected to result in an increase to our operating costs and changes in our operations.
In addition, several states are pursuing similar measures to regulate emissions of methane from new and existing
sources within the oil and natural gas source category. As a result of this continued regulatory focus, future federal
and state regulations of the oil and natural gas industry remain a possibility and could result in increased compliance
costs on our operations.

A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy
by It May Result in Increased Regulation of Our Assets, Which May Cause Our Revenues to Decline and
Operating Expenses to Increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. We
believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish
a pipeline’s status as a gatherer not subject to FERC regulation. However, the distinction between FERC-regulated
transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the
classiﬁcation and regulation of our gathering facilities are subject to change based on future determinations by FERC,
the courts or Congress. Similarly, intrastate crude oil pipeline facilities are exempt from regulation by FERC under

FORM 10-K PART I

2016 ANNUAL REPORT

the Interstate Commerce Act. We believe that the crude oil pipelines in our gathering systems meet the traditional
tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC regulation. However,
whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact dependent and
determined on a case-by-case basis. A change in the jurisdictional characterization of our facilities by FERC, the
courts or Congress, a change in policy by FERC or Congress or the expansion of our activities may result in increased
regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules, Regulations and Orders,
We Could Be Subject to Substantial Penalties and Fines.

Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current
violations of up to $1.0 million per day for each violation and disgorgement of proﬁts associated with any violation.
The nature of our gathering facilities is such that we have not yet been regulated by FERC. It is possible, however,
that laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or
Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject
us to civil penalty liability.

The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge
Risks Associated with Our Business.

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection

Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S. ﬁnancial system.
The Dodd-Frank Act, among other things, establishes federal oversight and regulation of certain derivative products,
including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading
Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although
the CFTC has ﬁnalized certain regulations, others remain to be ﬁnalized or implemented, and it is not possible at
this time to predict when, or if, this will be accomplished.

In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the

major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated
by the United States District Court for the District of Columbia in September 2012. However, in November 2013,
the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps
contracts for or linked to certain physical commodities, subject to exceptions for certain bona ﬁde hedging
transactions. As these new position limit rules are not yet ﬁnal, the impact of those provisions on us is uncertain at
this time. The Dodd-Frank Act could also result in additional regulatory requirements on our derivative arrangements,
which could include new margin, reporting and clearing requirements. In addition, this legislation could have a
substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future.

If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could
increase, which would increase the volatility of revenues and may decrease the amount of credit available to us.
Any limitations or changes in our use of derivative arrangements could also materially affect our cash ﬂows,
which could adversely affect our ability to make capital expenditures.

Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some

legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas.
Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing
regulations is to lower commodity prices.

Any of these consequences could have a material adverse effect on our business, ﬁnancial condition and results

of operations.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

We May Have Difﬁculty Managing Growth in Our Business, Which Could Have a Material Adverse Effect
on Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to Execute Our
Business Plan in a Timely Fashion.

Because of our size, growth in accordance with our business plans, if achieved, will place a signiﬁcant strain on

our ﬁnancial, technical, operational and management resources. As and when we expand our activities, including
our midstream business, through the Joint Venture or otherwise, there will be additional demands on our ﬁnancial,
technical and management resources. The failure to continue to upgrade our technical, administrative, operating and
ﬁnancial control systems or the occurrence of unexpected expansion difﬁculties, including the inability to recruit and
retain experienced managers, geoscientists, petroleum engineers, landmen, midstream professionals, attorneys
and ﬁnancial and accounting professionals, could have a material adverse effect on our business, ﬁnancial condition,
results of operations and cash ﬂows and our ability to execute our business plan in a timely fashion.

Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including Our
Chairman and Chief Executive Ofﬁcer, Management and Technical Team, the Members of Our Board of
Directors and Our Special Board Advisors, and the Loss of Any Key Personnel, Board Member or
Special Board Advisor Could Disrupt Our Business Operations.

Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management

and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our
performance and success are dependent to a large extent on the efforts and continued employment of our
management and technical personnel, including our Chairman and Chief Executive Ofﬁcer, Joseph Wm. Foran. We
do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their
successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key
personnel. However, these employment agreements do not ensure that these individuals will remain in our
employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if
they are not adequately replaced, our business operations could be adversely affected. With the exception of
Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

We have an active Board of Directors that meets at least quarterly throughout the year and is closely involved in
our business and the determination of our operational strategies. Members of our Board of Directors work closely
with management to identify potential prospects, acquisitions and areas for further development. Certain of our
directors have been involved with us since our inception and have a deep understanding of our operations and
culture. If any of our directors resign or become unable to continue in their present role, it may be difﬁcult to ﬁnd
replacements with the same knowledge and experience and, as a result, our operations may be adversely affected.

In addition, our board consults regularly with our special advisors regarding our business and the evaluation,
exploration, engineering and development of our prospects. Due to the knowledge and experience of our special
advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions
and development. If any of our special advisors resign or become unable to continue in their present role, our
operations may be adversely affected.

FORM 10-K PART I

2016 ANNUAL REPORT

Information Technology Systems Implementation Issues Could Disrupt Our Internal Operations, Increase
Our Costs and Could Have a Material Adverse Effect on Our Financial Results or Our Ability to Report Our
Financial Results.

We are currently in the process of implementing new information technology software systems to replace

certain of our legacy systems, including our accounting and land systems. As a part of this effort, we are transitioning
data and changing certain processes, which will require changes to our internal control over ﬁnancial reporting.
This implementation process may be more expensive, time consuming and resource intensive than planned. Any
disruptions that may occur in the implementation or operation of these systems updates or any future systems
that we implement could increase our expenses and have a material adverse effect on our ability to report in an
accurate and timely manner our ﬁnancial position, results of operations and cash ﬂows and to otherwise operate
our business.

A Cyber Incident Could Occur and Result in Information Theft, Data Corruption, Operational Disruption or
Financial Loss.

The oil and natural gas industry is dependent on digital technologies to conduct certain exploration, development,

production, gathering, processing and ﬁnancial activities. We depend on digital technology to, among other things,
estimate oil and natural gas reserves quantities, plan, execute and analyze drilling, completion, production,
gathering, processing and disposal operations, process and record ﬁnancial and operating data and communicate
with employees, shareholders, royalty owners and other third-party industry participants.

While we have not experienced any material losses due to cyber-attacks, we may suffer such losses in the

future. If our systems for protecting against cyber incidents prove to be insufﬁcient, we could be adversely affected
by unauthorized access to proprietary information, which could lead to data corruption, communication interruption,
exposure of our or third parties’ conﬁdential or proprietary information, operational disruptions or ﬁnancial loss. As
cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and
enhance our protective systems or to investigate and remediate any vulnerabilities.

RISKS RELATING TO OUR COMMON STOCK

The Price of Our Common Stock Has Fluctuated Substantially and May Fluctuate Substantially in the Future.

Our stock price has experienced volatility and could vary signiﬁcantly as a result of a number of factors. In 2016,

our stock price ﬂuctuated between a high of $27.71 and a low of $11.13. In addition, the trading volume of our
common stock may continue to ﬂuctuate and cause signiﬁcant price variations to occur. In the event of a drop in the
market price of our common stock, you could lose a substantial part or all of your investment in our common stock.
In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the
operating performance of particular companies. These broad market ﬂuctuations may adversely affect the trading
price of our common stock.

Factors that could affect our stock price or result in ﬂuctuations in the market price or trading volume of our

common stock include:

(cid:85) our actual or anticipated operating and ﬁnancial performance and drilling locations, including oil and natural

gas reserves estimates;

(cid:85) quarterly variations in the rate of growth of our ﬁnancial indicators, such as net income per share, net

income and cash ﬂows, or those of companies that are perceived to be similar to us;

(cid:85) changes in revenue, cash ﬂows or earnings estimates or publication of reports by equity research analysts;

(cid:85) speculation in the press or investment community;

FORM 10-K PART I

MATADOR RESOURCES COMPANY

(cid:85) announcement or consummation of acquisitions or dispositions by us;

(cid:85) public reaction to our press releases, announcements and ﬁlings with the SEC;

(cid:85) sales of our common stock by us or shareholders, or the perception that such sales may occur;

(cid:85) general ﬁnancial market conditions and oil and natural gas industry market conditions, including ﬂuctuations

in the price of oil, natural gas and natural gas liquids;

the realization of any of the risk factors presented in this Annual Report;

the recruitment or departure of key personnel;

(cid:85)

(cid:85) commencement of or involvement in litigation;

(cid:85)

the success of our exploration and development operations, our midstream business and the marketing
of any oil, natural gas and natural gas liquids we produce;

(cid:85) changes in market valuations of companies similar to ours; and

(cid:85) domestic and international economic, legal and regulatory factors unrelated to our performance.

If We Fail to Maintain Effective Internal Control over Financial Reporting in the Future, Our Ability to
Accurately Report Our Financial Results Could Be Adversely Affected.

As a public company with listed equity securities, we are required to comply with laws, regulations and

requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of
the SEC and the requirements of the NYSE. Complying with these statutes, regulations and requirements is difﬁcult
and costly and occupies a signiﬁcant amount of time of our Board of Directors and management.

Pursuant to the Sarbanes-Oxley Act, we are required to maintain internal control over ﬁnancial reporting. Our
efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls
over our ﬁnancial processes and reporting in the future and comply with the certiﬁcation and reporting obligations
under Sections 302 and 404 of the Sarbanes-Oxley Act. Our management does not expect that our internal controls
and disclosure controls will prevent all possible error or all fraud. Further, our remediation efforts may not enable us
to avoid material weaknesses in the future. Any failure to maintain effective controls could result in material
misstatements that are not prevented or detected and corrected on a timely basis, which could potentially subject
us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls
could also cause investors to lose conﬁdence in our reported ﬁnancial information and adversely affect our business
and our stock price.

We Do Not Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares of Our Common Stock.

We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock.
Any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other
things, our earnings, ﬁnancial condition, capital requirements, level of indebtedness, statutory and contractual
restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems
relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience
substantial losses, such funds may not be available. In addition, certain covenants in our Credit Agreement and
the indenture governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of
our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate
cash ﬂow from your investment, and there is no guarantee that the price of our common stock will exceed the
price you paid.

FORM 10-K PART I

2016 ANNUAL REPORT

Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings of Our
Common Stock by Us Could Depress the Price of Our Common Stock.

The market price of our common stock could decline as a result of sales of a large number of shares of our
common stock in the market, including shares of equity or debt securities convertible into common stock, and the
perception that these sales could occur may also depress the market price of our common stock. If our existing
shareholders sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the
trading price of our common stock could decline signiﬁcantly. Sales of our common stock may make it more
difﬁcult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales
could also cause our stock price to decrease and make it more difﬁcult for you to sell shares of our common stock.

We may also sell or issue additional shares of common stock or equity or debt securities convertible into

common stock in public or private offerings or in connection with acquisitions. We cannot predict the size of future
issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales
of shares of our common stock or convertible securities would have on the market price of our common stock.

Provisions of Our Certiﬁcate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects That
Could Prevent a Change in Control Even if It Might Be Beneﬁcial to Our Shareholders.

Our certiﬁcate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger

or acquisition that our shareholders may consider favorable. These provisions include:

(cid:85) authorization for our Board of Directors to issue preferred stock without shareholder approval;

(cid:85) a classiﬁed Board of Directors so that not all members of our Board of Directors are elected at one time;

(cid:85)

the prohibition of cumulative voting in the election of directors; and

(cid:85) a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our

outstanding shares of common stock.

Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us,

which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneﬁcially
owns more than 20% of our voting stock, or an afﬁliated shareholder, cannot acquire us for a period of three years
from the date this person became an afﬁliated shareholder, unless various conditions are met, such as approval
of the transaction by our Board of Directors before this person became an afﬁliated shareholder or approval of the
holders of at least two-thirds of our outstanding voting shares not beneﬁcially owned by the afﬁliated shareholder.

Our Directors and Executive Ofﬁcers Own a Signiﬁcant Percentage of Our Equity, Which Could Give Them
Inﬂuence in Corporate Transactions and Other Matters, and the Interests of Our Directors and Executive
Ofﬁcers Could Differ from Other Shareholders.

As of February 22, 2017, our directors and executive ofﬁcers beneﬁcially owned approximately 12% of our

outstanding common stock. These shareholders could inﬂuence or control to some degree the outcome of matters
requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certiﬁcate
of formation or bylaws and the approval of mergers and other signiﬁcant corporate transactions. Their inﬂuence or
control of the Company may have the effect of delaying or preventing a change of control of the Company and
may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in
our common stock, our directors and executive ofﬁcers may be able to remain entrenched in their positions.

FORM 10-K PART I

MATADOR RESOURCES COMPANY

Our Board of Directors Can Authorize the Issuance of Preferred Stock, Which Could Diminish the Rights of
Holders of Our Common Stock and Make a Change of Control of the Company More Difﬁcult Even if It Might
Beneﬁt Our Shareholders.

Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to ﬁx the voting

powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of
preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or
dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock.

Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock,
may have the effect of delaying, deterring or preventing a change of control of the Company, even if that change of
control might beneﬁt our shareholders.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

Not applicable.

ITEM 2. PROPERTIES.

See “Business” for descriptions of our properties. We also have various operating leases for rental of ofﬁce

space and ofﬁce and ﬁeld equipment. See Note 13 to the consolidated ﬁnancial statements in this Annual Report for
the future minimum rental payments. Such information is incorporated herein by reference.

ITEM 3. LEGAL PROCEEDINGS.

We are a party to several lawsuits encountered in the ordinary course of our business. While the ultimate

outcome and impact to us cannot be predicted with certainty, in the opinion of management, it is remote that these
lawsuits will have a material adverse impact on our ﬁnancial condition, results of operations or cash ﬂows.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable.

FORM 10-K PART I

2016 ANNUAL REPORT

Part II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS

AND ISSUER PURCHASES OF EQUITY SECURITIES.

GENERAL MARKET INFORMATION

Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded
on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for
our common stock.

On February 24, 2017, we had 100,034,559 shares of common stock outstanding held by approximately 300

record holders, excluding shareholders for whom shares are held in “nominee” or “street” name.

The following table sets forth the high and low sales prices of our common stock as reported by the NYSE for

the periods indicated.

First Quarter
Second Quarter
Third Quarter
Fourth Quarter

2016

2015

High

Low

High

Low

$ 20.94
$ 25.54
$ 24.71
$ 27.71

$ 11.13
$ 18.03
$ 18.56
$ 20.45

$25.08
$29.90
$26.07
$28.25

$18.28
$22.01
$19.08
$18.87

On February 24, 2017, the last reported sales price of our common stock on the NYSE was $24.42 per share.

DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable
future. We currently intend to retain future earnings to ﬁnance the expansion of our business. Our future dividend
policy is within the discretion of our Board of Directors and will depend upon various factors, including our results of
operations, ﬁnancial condition, capital requirements and investment opportunities. In addition, certain covenants in
our Credit Agreement and the indenture governing our outstanding senior notes may limit our ability to pay dividends
on our common stock. During the years ended December 31, 2016 and 2015, we did not pay dividends to holders
of our common stock.

EQUITY COMPENSATION PLAN INFORMATION

The following table presents the securities authorized for issuance under our equity compensation plans as of

December 31, 2016.

Plan Category

Equity compensation plans approved by security holders (1) (2)
Equity compensation plans not approved by security holders

Total

Equity Compensation Plan Information

Number of Shares
to be Issued
Upon Exercise of
Outstanding Options,
Warrants and Rights

Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights

Number of Shares
Remaining Available
for Future Issuance
Under Equity
Compensation Plans

2,872,954
—
2,872,954

$ 15.59
—
$ 15.59

3,963,427
—
3,963,427

(1) Our Board of Directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock and

Incentive Plan.

(2) The Amended and Restated 2012 Long-Term Incentive Plan was adopted by our Board of Directors in April 2015 and approved by our

shareholders on June 10, 2015. For a description of our Amended and Restated 2012 Long-Term Incentive Plan, see Note 8 to the consolidated
ﬁnancial statements in this Annual Report.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

SHARE PERFORMANCE GRAPH

The following graph compares the cumulative return on a $100 investment in our common stock from

February 2, 2012, the date our common stock began trading on the NYSE, through December 31, 2016, to that
of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for
the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed.

This graph is not “soliciting material,” is not deemed ﬁled with the SEC and is not to be incorporated by reference

in any of our ﬁlings under the Securities Act or the Exchange Act, whether made before or after the date hereof
and irrespective of any general incorporation language in any such ﬁling. This graph is included in accordance with
the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance.

COMPARISON OF CUMULATIVE TOTAL RETURN AMONG MATADOR RESOURCES COMPANY,
THE RUSSELL 2000 INDEX AND THE RUSSELL 2000 ENERGY INDEX

300

250

200

150

100

02/02/12

06/30/12

12/31/12

06/30/13

12/31/13

06/30/14

12/31/14

06/30/15

12/31/15

06/30/16

12/31/16

MTDR

Russell 2000

Russell 2000 Energy

FORM 10-K PART I I

2016 ANNUAL REPORT

REPURCHASE OF EQUITY BY THE COMPANY OR AFFILIATES

During the quarter ended December 31, 2016, the Company re-acquired shares of common stock from certain

employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock.

Period

Total Number of
Shares Purchased (1)

Average Price Paid
Per Share

Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs

Maximum Number of
Shares that May Yet
Be Purchased Under
the Plans or Programs

October 1, 2016 to October 31, 2016
November 1, 2016 to November 30, 2016
December 1, 2016 to December 31, 2016

Total

1,131
1,288
1,306
3,725

$ 23.66
21.45
25.65
$ 23.59

—
—
—
—

(1) The shares were not re-acquired pursuant to any repurchase plan or program.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

ITEM 6. SELECTED FINANCIAL DATA.

The following selected ﬁnancial information is summarized from our results of operations for the ﬁve-year period

ended December 31, 2016 and selected consolidated balance sheet and cash ﬂow data at December 31, 2016,
2015, 2014, 2013 and 2012. You should read the following selected ﬁnancial data in conjunction with “Management’s
Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated ﬁnancial
statements and related notes thereto included elsewhere in this Annual Report. The ﬁnancial information included
in this Annual Report may not be indicative of our future results of operations, ﬁnancial condition or cash ﬂows.

(In thousands, except per share data)

Statement of operations data:
Revenues

Oil and natural gas revenues
Third-party midstream services revenue
Realized gain (loss) on derivatives
Unrealized (loss) gain on derivatives
Total revenues

Expenses

Year Ended December 31,

2016

2015

2014

2013

2012

$ 291,156
5,218
9,286
(41,238)
264,422

$ 278,340
1,864
77,094
(39,265)
318,033

$ 367,712
1,213
5,022
58,302
432,249

$269,030
207
(909)
(7,232)
261,096

$155,998
183
13,960
(4,802)
165,339

Production taxes, transportation and processing (1)
Lease operating (2)
Plant and other midstream services operating
Depletion, depreciation and amortization
Accretion of asset retirement obligations
Full-cost ceiling impairment
General and administrative
Total expenses

Operating (loss) income

Other income (expense)

Net gain (loss) on asset sales and inventory impairment
Interest expense
Other (expense) income (3)

Total other income (expense)

Net (loss) income

Net (income) loss attributable to non-controlling

43,046
56,202
5,389
122,048
1,182
158,633
55,089
441,589
(177,167)

107,277
(28,199)
(4)
79,074
(97,057)

35,650
54,704
3,489
178,847
734
801,166
50,105
1,124,695
(806,662)

33,172
49,945
1,408
134,737
504
—
32,152
251,918
180,331

20,973
37,971
749
98,395
348
21,229
20,779
200,444
60,652

908
(21,754)
616
(20,230)
(679,524)

—
(5,334)
132
(5,202)
110,754

(192)
(5,687)
18
(5,861)
45,094

11,672
27,868
316
80,454
256
63,475
14,543
198,584
(33,245)

(485)
(1,002)
42
(1,445)
(33,261)

interest in subsidiaries

(364)

(261)

—

Net (loss) income attributable to
Matador Resources Company shareholders

Earnings (loss) per common share
Basic
Class A (4)

Class B (4)

Diluted
Class A (4)

Class B (4)

Class B dividend declared, per share (4)

$ (97,421)

$ (679,785)

$ 110,771

$ 45,094

$ (33,261)

(1.07)

(8.34)

1.58

0.77

(0.62)

— $

(0.35)

(1.07)

(8.34)

1.56

0.77

(0.62)

— $

(0.35)

— $

0.27

(1) $0.1 million was reclassiﬁed to third-party midstream services revenues for the year ended December 31, 2015 due to our midstream business

becoming a reportable segment in the third quarter of 2016. There were no such reclassiﬁcations made in any other periods presented.

(2) $3.5 million, $1.4 million, $0.7 million and $0.3 million were reclassiﬁed to plant and other midstream services operating expenses for the years ended
December 31, 2015, 2014, 2013 and 2012, respectively, due to our midstream business becoming a reportable segment in the third quarter of 2016.

(3) $1.7 million, $1.2 million, $0.2 million and $0.2 million were reclassiﬁed to midstream services revenues for the years ended December 31, 2015,

2014, 2013 and 2012, respectively, due to our midstream business becoming a reportable segment in the third quarter of 2016.

(4) Our Class B common stock converted into Class A common stock upon the consummation of our initial public offering on February 7, 2012 and the
Class A common stock then became the only class of common stock authorized. The term “Class A common stock” refers to shares of our Class A
common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of our initial
public offering.

FORM 10-K PART I I

2016 ANNUAL REPORT

2016

2015

2014

2013

2012

At December 31,

$ 212,884
1,258
—
1,184,525
1,464,665
169,505
603,715

16,732
44,357
—
1,012,406
1,140,861
136,830
515,072

8,407
609
—
1,322,072
1,434,490
142,036
425,913

6,287
—
—
845,877
890,330
100,327
221,079

2,095
—
230
591,090
632,029
96,492
156,433

$ 690,125

$ 488,003

$ 866,408

$ 568,924

$ 379,104

2016

2015

2014

2013

2012

Year Ended December 31,

$ 134,086

$ 208,535

$ 251,481 $ 179,470

(405,640)
(379,067)
(74,845)
467,706
$ 157,928

(425,154)
(432,715)
(64,499)
224,944
$ 223,155

(570,531)
(560,849)

(366,939)
(363,192)
(9,152) (3,977)
191,661
$ 191,771

321,170
$ 262,943

$ 124,228
(306,916)
(300,689)
(7,332)
174,499
$ 115,923

(In thousands)

Balance sheet data:
Cash and cash equivalents
Restricted cash
Certiﬁcates of deposit
Net property and equipment
Total assets
Current liabilities
Long-term liabilities
Total Matador Resources Company

shareholders’ equity

(In thousands)

Other ﬁnancial data:
Net cash provided by operating activities
Net cash used in investing activities

Oil and natural gas properties capital expenditures
Expenditures for other property and equipment

Net cash provided by ﬁnancing activities
Adjusted EBITDA (1)

(1) Adjusted EBITDA is a non-GAAP ﬁnancial measure. For a deﬁnition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net

income (loss) and net cash provided by operating activities, see “ – Non-GAAP Financial Measures” below.

NON-GAAP FINANCIAL MEASURES

We deﬁne Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and

amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses,
certain other non-cash items and non-cash stock-based compensation expense, and net gain or loss on asset
sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or cash ﬂows as
determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP ﬁnancial measure that is used by management
and external users of our consolidated ﬁnancial statements, such as industry analysts, investors, lenders and
rating agencies.

Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance

and compare the results of operations from period to period without regard to our ﬁnancing methods or capital
structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA, because these
amounts can vary substantially from company to company within our industry depending upon accounting methods
and book values of assets, capital structures and the method by which certain assets were acquired.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash ﬂows

from operating activities as determined in accordance with GAAP or as a primary indicator of our operating
performance or liquidity. Certain items excluded from Adjusted EBITDA are signiﬁcant components of understanding
and assessing a company’s ﬁnancial performance, such as a company’s cost of capital and tax structure. Our
Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies
may not calculate Adjusted EBITDA in the same manner.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to

the GAAP ﬁnancial measures of net income (loss) and net cash provided by operating activities, respectively.

Year Ended December 31,

2016

2015

2014

2013

2012

(In thousands)

Unaudited Adjusted EBITDA Reconciliation to
Net (Loss) Income:
Net (loss) income attributable to

Matador Resources Company shareholders

Interest expense
Total income tax (beneﬁt) provision
Depletion, depreciation and amortization
Accretion of asset retirement obligations
Full-cost ceiling impairment
Unrealized loss (gain) on derivatives
Stock-based compensation expense
Net (gain) loss on asset sales and inventory impairment

Adjusted EBITDA

(In thousands)

Unaudited Adjusted EBITDA Reconciliation to
Net Cash Provided by Operating Activities:
Net cash provided by operating activities
Net change in operating assets and liabilities
Interest expense, net of non-cash portion
Current income tax (beneﬁt) provision
Net (income) loss attributable to non-controlling

$ (97,421)
28,199
(1,036)
122,048
1,182
158,633
41,238
12,362
(107,277)

$(679,785)
21,754
(147,368)
178,847
734
801,166
39,265
9,450
(908)

$ 157,928

$ 223,155

$110,771
5,334
64,375
134,737
504
—
(58,302)
5,524
—
$262,943

$ 45,094
5,687
9,697
98,395
348
21,229
7,232
3,897
192
$191,771

$ (33,261)
1,002
(1,430)
80,454
256
63,475
4,802
140
485
$115,923

Year Ended December 31,

2016

2015

2014

2013

2012

$ 134,086

$ 208,535

(1,809)
27,051
(1,036)

(8,980)
20,902
2,959

$251,481
5,978
5,334
133

$179,470
6,210
5,687
404

$124,228
(9,307)
1,002
—

interest in subsidiaries
Adjusted EBITDA

(364)

(261)

$ 157,928

$ 223,155

17
$262,943

—
$191,771

—
$115,923

FORM 10-K PART I I

2016 ANNUAL REPORT

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS.

The following discussion and analysis of our ﬁnancial condition and results of operations should be read in

conjunction with our consolidated ﬁnancial statements and related notes appearing elsewhere in this Annual Report.
The following discussion contains “forward-looking statements” that reﬂect our future plans, estimates, beliefs
and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about
future events may, and often do, vary from actual results and the differences can be material. Some of the key
factors which could cause actual results to vary from our expectations include changes in oil or natural gas prices,
the timing of planned capital expenditures, availability under our Credit Agreement borrowing base, uncertainties
in estimating proved reserves and forecasting production results, operational factors affecting the commencement
or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access
them, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration
of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory
developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report,
all of which are difﬁcult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events
discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.”

OVERVIEW

We are an independent energy company founded in July 2003 and engaged in the exploration, development,
production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural
gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich
portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas.
We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in
Northwest Louisiana and East Texas. Additionally, we conduct midstream operations primarily, as of February 17, 2017,
through San Mateo in support of our exploration, development and production operations and provide natural gas
processing, natural gas, oil and salt water gathering services and salt water disposal services to third parties on a
limited basis.

2016 Operational Highlights

During the year ended December 31, 2016, we completed and began producing oil and natural gas from 40 gross

(35.6 net) operated and 15 gross (1.4 net) non-operated wells in the Delaware Basin. We did not conduct any
operated drilling and completion activities on our leasehold properties in South Texas or in Northwest Louisiana and
East Texas during 2016, although we did participate in the drilling and completion of 15 gross (2.1 net) non-operated
Haynesville shale wells and two gross (less than 0.1 net) non-operated Eagle Ford shale wells that began producing
in 2016.

At January 1, 2016, we were operating three drilling rigs in the Delaware Basin in Southeast New Mexico and

West Texas, and we operated these drilling rigs in certain of our various asset areas in the Delaware Basin
throughout most of 2016. We contracted a fourth drilling rig in late August 2016 to begin drilling our ﬁrst salt water
disposal well in our Rustler Breaks asset area in Eddy County, New Mexico. After we ﬁnished drilling that well,
we moved the rig to our Wolf asset area in Loving County, Texas to drill a third salt water disposal well there. In late
November 2016, we elected to move this fourth drilling rig back to our Rustler Breaks asset area to begin drilling
oil and natural gas wells there. At December 31, 2016 and February 22, 2017 we continued to operate four drilling
rigs in the Delaware Basin, including two rigs in our Rustler Breaks asset area, one rig in our Wolf asset area and
one rig in our Ranger and Arrowhead asset areas in Lea and Eddy Counties, New Mexico. The vast majority of our
2016 capital expenditures of $454.4 million were directed to the delineation and development of our leasehold
position in the Delaware Basin, to the development of certain midstream assets to support our operations there and

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

to the acquisition of additional leasehold interests prospective for the Wolfcamp, Bone Spring and other liquids-rich
plays in the Delaware Basin. Our remaining capital expenditures were directed to the installation of pumping units
and other facilities on certain of our Eagle Ford shale wells in South Texas and to our participation in several non-
operated wells drilled and completed in the Eagle Ford and Haynesville shales throughout 2016, as noted above.

We increased our leasehold position signiﬁcantly in the Delaware Basin during 2016. At December 31, 2016, we

held approximately 163,700 gross (94,300 net) acres in the Permian Basin in Southeast New Mexico and West
Texas, primarily in the Delaware Basin in Lea and Eddy Counties, New Mexico and Loving County, Texas. Between
January 1, 2017 and February 22, 2017, we acquired approximately 13,900 gross (8,200 net) leasehold and mineral
acres and approximately 1,000 BOE per day of related production from various lessors and other operators, mostly
in and around our existing acreage in the Delaware Basin. This brought our total Permian Basin acreage position
at February 22, 2017 to 177,600 gross (101,400 net) acres, almost all of which was located in the Delaware Basin.

Our oil production, natural gas production and average daily oil equivalent production during 2016 were the best

in the Company’s history. Our average daily oil equivalent production for the year ended December 31, 2016 was
27,813 BOE per day, including 13,924 Bbl of oil per day and 83.3 MMcf of natural gas per day, an increase of 12%
as compared to 24,955 BOE per day, including 12,306 Bbl of oil per day and 75.9 MMcf of natural gas per day, for
the year ended December 31, 2015. Our average daily oil production in 2016 of 13,924 Bbl of oil per day increased
13%, as compared to an average daily oil production of 12,306 Bbl of oil per day in 2015. This increase in oil
production was primarily a result of our ongoing delineation and development drilling in the Delaware Basin, which
offset declining oil production in the Eagle Ford shale where we have not drilled any new operated wells since
the second quarter of 2015. Our average daily natural gas production of 83.3 MMcf per day for the year ended
December 31, 2016 increased 10% from 75.9 MMcf per day for the year ended December 31, 2015. This increase
in natural gas production was primarily attributable to increased natural gas production associated with our operations
in the Delaware Basin and new, non-operated Haynesville shale wells completed and placed on production on our
Elm Grove properties in Northwest Louisiana in the latter half of 2015 and into 2016. Oil production comprised 50%
of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended
December 31, 2016, as compared to 49% for the year ended December 31, 2015.

For the year ended December 31, 2016, our oil and natural gas revenues were $291.2 million, an increase of
5% from oil and natural gas revenues of $278.3 million for the year ended December 31, 2015. Our oil revenues
and natural gas revenues increased 3% and 8% to approximately $209.9 million and $81.2 million, respectively,
as a result of the increases in oil and natural gas production for the year ended December 31, 2016 as noted above, as
compared to $203.4 million and $75.0 million, respectively, for the year ended December 31, 2015. The increase
in both oil and natural gas production in 2016 helped to mitigate the impacts of somewhat lower realized weighted
average oil and natural gas prices of $41.19 per Bbl and $2.66 per Mcf in 2016, respectively, as compared to
$45.27 per Bbl and $2.71 per Mcf in 2015, respectively.

We reported a net loss of approximately $97.4 million, or $1.07 per diluted common share on a GAAP basis for

the year ended December 31, 2016, as compared to a net loss of $679.8 million, or $8.34 per diluted common
share, for the year ended December 31, 2015. Our net loss and net loss per diluted common share on a GAAP basis
were signiﬁcantly impacted by full-cost ceiling impairments of $158.6 million and $801.2 million for the years
ended December 31, 2016 and 2015, respectively, as a result of substantial declines in oil and natural gas prices
throughout 2015 and 2016. Adjusted EBITDA for the year ended December 31, 2016 was $157.9 million, as
compared to Adjusted EBITDA of $223.2 million reported for the year ended December 31, 2015. This decrease in
Adjusted EBITDA resulted, in part, from the lower weighted average oil and natural gas prices realized in 2016,
but was primarily attributable to lower realized hedging revenues of $9.3 million in 2016, as compared to $77.1 million
in 2015. Adjusted EBITDA is a non-GAAP ﬁnancial measure. For a deﬁnition of Adjusted EBITDA and a reconciliation
of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial
Data — Non-GAAP Financial Measures.”

FORM 10-K PART I I

2016 ANNUAL REPORT

At December 31, 2016, our estimated total proved oil and natural gas reserves were 105.8 million BOE, an
all-time high for the Company, including 57.0 million Bbl of oil and 292.6 Bcf of natural gas, with a Standardized
Measure of $575.0 million and a PV-10 of $581.5 million. At December 31, 2015, our estimated proved oil and
natural gas reserves were 85.1 million BOE, including 45.6 million Bbl of oil and 236.9 Bcf of natural gas, with a
Standardized Measure of $529.2 million and a PV-10 of $541.6 million. Our estimated total proved reserves of
105.8 million BOE at December 31, 2016 represented a 24% year-over-year increase, as compared to 85.1 million
BOE at December 31, 2015. Our estimated proved oil reserves of 57.0 million Bbl at December 31, 2016
increased 25%, as compared to 45.6 million Bbl at December 31, 2015. Our proved oil and natural gas reserves in
the Delaware Basin increased 68% to 79.4 million BOE at December 31, 2016, as compared to 47.1 million BOE
at December 31, 2015, as a result of our ongoing delineation and development operations in the Delaware Basin.
At December 31, 2016, approximately 75% of our total proved oil and natural gas reserves were attributable to
our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin increased 49% to 46.9 million
Bbl at December 31, 2016, as compared to 31.4 million Bbl at December 31, 2015. Proved oil reserves comprised
54% of our total proved reserves at both December 31, 2016 and December 31, 2015. These reserves estimates
were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and
conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
Standardized Measure represents the present value of estimated future net cash ﬂows from proved reserves, less
estimated future development, production, plugging and abandonment costs and income tax expenses, discounted
at 10% per annum to reﬂect the timing of future cash ﬂows. Standardized Measure is not an estimate of the fair
market value of our properties. PV-10 is a non-GAAP ﬁnancial measure. For a reconciliation of PV-10 to Standardized
Measure, see “Business — Estimated Proved Reserves.”

2017 Midstream Joint Venture

On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary of

Five Point to operate and expand our Delaware Midstream Assets. We received $171.5 million in connection with
the formation of the Joint Venture and may earn up to an additional $73.5 million in performance incentives over the
next ﬁve years. We continue to operate the Delaware Midstream Assets and retain operational control of the
Joint Venture. The Company and Five Point own 51% and 49% of the Joint Venture, respectively. San Mateo will
continue to provide ﬁrm capacity service to us at market rates, while also being a midstream service provider to
third parties in and around our Wolf and Rustler Breaks asset areas.

2017 Capital Expenditure Budget

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital

expenditures in 2017. We plan to operate four contracted drilling rigs in the Delaware Basin during the ﬁrst quarter
of 2017 and expect to add a ﬁfth drilling rig in the Delaware Basin in the second quarter of 2017. Our 2017 estimated
capital expenditure budget consists of $370 to $390 million for drilling, completions, facilities and infrastructure and
$56 to $64 million for midstream capital expenditures, which represents our 51% share of an estimated 2017 capital
expenditure budget of $110 to $125 million for San Mateo. Substantially all of our 2017 estimated capital
expenditures will be allocated to the further delineation and development of our growing leasehold position and
midstream assets in the Delaware Basin, with the exception of amounts allocated to limited operations in the Eagle
Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated well
opportunities. Our 2017 Delaware Basin drilling program will focus on the continued development of the Wolf and
Rustler Breaks asset areas and the further delineation and development of the Jackson Trust, Ranger/Arrowhead
and Twin Lakes asset areas, although we do anticipate continuing to delineate previously untested zones in the Wolf
and Rustler Breaks asset areas during 2017.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

We intend to continue acquiring acreage and mineral interests, principally in the Delaware Basin, during 2017.

These expenditures are opportunity-speciﬁc and per-acre prices can vary signiﬁcantly based on the prospect.
As a result, it is difﬁcult to estimate these 2017 capital expenditures with any degree of certainty; therefore, we
have not provided estimated capital expenditures related to acreage and mineral acquisitions for 2017.

At December 31, 2016, we had $212.9 million in cash (excluding restricted cash) and $399.2 million in undrawn

borrowing capacity under our Credit Agreement (after giving effect to outstanding letters of credit). As a result,
we expect to fund our capital expenditures for 2017 through a combination of cash on hand, operating cash ﬂows,
proceeds we received in connection with the formation of the Joint Venture and borrowings under our Credit
Agreement (assuming availability under our borrowing base). We may also consider funding a portion of our 2017
capital expenditures through additional credit arrangements, the sale or joint venture of midstream assets or oil
and natural gas producing assets or acreage, particularly in our non-core asset areas, as well as potential issuances
of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. The
aggregate amount of capital we expend may ﬂuctuate materially based on market conditions, the actual costs to
drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs of our
midstream activities, other opportunities that may become available to us and our ability to obtain capital.

REVENUES

Our revenues are derived primarily from the sale of oil, natural gas and natural gas liquids production. Our
revenues may vary signiﬁcantly from period to period as a result of changes in volumes of production sold or
changes in oil, natural gas or natural gas liquids prices.

The following table summarizes our revenues and production data for the periods indicated.

Operating Data:
Revenues (in thousands): (1)

Oil
Natural gas

Total oil and natural gas revenues
Third-party midstream services revenues
Realized gain on derivatives
Unrealized (loss) gain on derivatives

Total revenues

Net Production Volumes: (1)
Oil (MBbl)
Natural gas (Bcf)

Total oil equivalent (MBOE) (2)
Average daily production (BOE/d) (2)

Average Sales Prices:
Oil, without realized derivatives (per Bbl)
Oil, with realized derivatives (per Bbl)
Natural gas, without realized derivatives (per Mcf)
Natural gas, with realized derivatives (per Mcf)

Year Ended December 31,

2016

2015

2014

$ 209,908
81,248
291,156
5,218
9,286
(41,238)

$ 264,422

5,096
30.5
10,180
27,813

$203,355
74,985
278,340
1,864
77,094
(39,265)
$318,033

4,492
27.7
9,109
24,955

$290,026
77,686
367,712
1,213
5,022
58,302
$432,249

3,320
15.3
5,870
16,082

$ 41.19
$ 42.34
2.66
2.78

$
$

$
$
$
$

45.27
59.13
2.71
3.24

$
$
$
$

87.37
88.94
5.08
5.06

(1) We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated

with natural gas liquids are included with our natural gas revenues.

(2) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

FORM 10-K PART I I

2016 ANNUAL REPORT

Year Ended December 31, 2016 as Compared to Year Ended December 31, 2015

Oil and natural gas revenues. Our oil and natural gas revenues increased $12.8 million to $291.2 million, or

an increase of 5%, for the year ended December 31, 2016, as compared to $278.3 million for the year ended
December 31, 2015. Our oil revenues increased $6.6 million, or an increase of 3%, to $209.9 million for the year
ended December 31, 2016, as compared to $203.4 million for the year ended December 31, 2015. The increase in
oil revenues resulted from the 13% increase in our oil production to 5.1 million Bbl of oil for the year ended
December 31, 2016, or about 13,924 Bbl of oil per day, as compared to 4.5 million Bbl of oil, or about 12,306 Bbl of
oil per day, for the year ended December 31, 2015. This increased oil production was primarily a result of our
ongoing delineation and development drilling in the Delaware Basin, which offset declining oil production in the
Eagle Ford shale, where we have not drilled any new operated wells since the second quarter of 2015. The
increase in oil revenues was partially impacted by a lower weighted average oil price realized for the year ended
December 31, 2016 of $41.19 per Bbl, as compared to $45.27 per Bbl realized for the year ended December 31,
2015. Our natural gas revenues increased $6.3 million, or an increase of 8%, to $81.2 million for the year ended
December 31, 2016, as compared to $75.0 million for the year ended December 31, 2015. The increase in natural
gas revenues resulted from the 10% increase in our natural gas production to 30.5 Bcf for the year ended
December 31, 2016, as compared to 27.7 Bcf for the year ended December 31, 2015. The increased natural gas
production was primarily attributable to our ongoing delineation and development drilling in the Delaware Basin,
which offset declining natural gas production in the Eagle Ford and Haynesville shales where we have signiﬁcantly
reduced our activity since late 2014 and early 2015. The increase in natural gas revenues was partially impacted
by a lower weighted average natural gas price realized for the year ended December 31, 2016 of $2.66 per Mcf, as
compared to $2.71 per Mcf realized for the year ended December 31, 2015.

Third-party midstream services revenues. During the third quarter of 2016, our midstream operations became

a reportable business segment under GAAP. Our third-party midstream services revenues were previously
included in other income. Third-party midstream services revenues are primarily those revenues from midstream
operations related to third parties, including working interest owners in our operated wells; all midstream services
revenues associated with our production are eliminated in consolidation. Our third-party midstream services
revenues increased to $5.2 million, or an increase of almost three-fold, for the year ended December 31, 2016,
as compared to $1.9 million for the year ended December 31, 2015. This increase was primarily attributable to a
signiﬁcant increase in third-party salt water disposal revenue to approximately $1.6 million for the year ended
December 31, 2016, as compared to $0.2 million for the year ended December 31, 2015, due to increased salt
water disposal at our facilities in the Wolf asset area in 2016. The remaining increase was primarily attributable
to third-party natural gas gathering and processing fees of $3.6 million for the year ended December 31, 2016, as
compared to $1.7 million for the year ended December 31, 2015, including natural gas processing at the Black
River Processing Plant, which began operating in August 2016.

Realized gain on derivatives. Our realized net gain on derivatives was $9.3 million for the year ended

December 31, 2016, as compared to a realized net gain of $77.1 million for the year ended December 31, 2015. We
realized net gains of $5.9 million and $3.4 million from our oil and natural gas derivative contracts, respectively,
for the year ended December 31, 2016 resulting from oil and natural gas prices that were below the ﬂoor prices of
certain of our oil and natural gas costless collar contracts. Our realized net gain on derivatives was $77.1 million
for the year ended December 31, 2015. We realized net gains of $62.3 million, $12.7 million and $2.2 million
from our oil, natural gas and natural gas liquid (“NGL”) derivative contracts, respectively, for the year ended
December 31, 2015 resulting from oil and natural gas prices being below the ﬂoor prices of most of our oil and
natural gas costless collar contracts and NGL prices being below the ﬁxed prices of all of our swap contracts. We
realized an average gain of approximately $2.29 per Bbl hedged on all of our open oil costless collar contracts
during the year ended December 31, 2016, as compared to an average gain of $22.89 per Bbl hedged for the year
ended December 31, 2015. Our oil volumes hedged for the year ended December 31, 2016 were also 6% lower as

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

compared to the year ended December 31, 2015. We realized an average gain of approximately $0.26 per MMBtu
hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2016, as
compared to an average gain of approximately $0.73 per MMBtu hedged on all of our open natural gas costless
collar contracts during the year ended December 31, 2015. Our total natural gas volumes hedged for the year
ended December 31, 2016 were also 23% lower than the total natural gas volumes hedged for the year ended
December 31, 2015.

Unrealized gain (loss) on derivatives. Our unrealized net loss on derivatives was $41.2 million for the year
ended December 31, 2016, as compared to an unrealized net loss of $39.3 million for the year ended December 31,
2015. During the year ended December 31, 2016, the net fair value of our open oil and natural gas derivatives
contracts decreased to a net liability of approximately $25.0 million from a net asset of $16.3 million for the year
ended December 31, 2015, resulting in an unrealized net loss on derivatives of $41.2 million for the year ended
December 31, 2016. During the year ended December 31, 2016, the net fair value of our open oil and natural gas
derivative contracts decreased $32.2 million and $9.1 million, respectively, due to the increase in the underlying oil
and natural gas futures prices at December 31, 2016, as well as realized gains from oil and natural gas derivative
contracts settled during the year ended December 31, 2016.

Year Ended December 31, 2015 as Compared to Year Ended December 31, 2014

Oil and natural gas revenues. Our oil and natural gas revenues decreased $89.4 million to $278.3 million, or

a decrease of 24%, for the year ended December 31, 2015, as compared to $367.7 million for the year ended
December 31, 2014. Our oil revenues decreased $86.7 million, a decrease of 30%, to $203.4 million for the year
ended December 31, 2015, as compared to $290.0 million for the year ended December 31, 2014. The decrease in
oil revenues resulted from a signiﬁcantly lower weighted average oil price realized for the year ended December 31,
2015 of $45.27 per Bbl, as compared to $87.37 per Bbl realized for the year ended December 31, 2014. The lower
weighted average oil price was partially mitigated by the 35% increase in our oil production to 4.5 million Bbl of oil
for the year ended December 31, 2015, or about 12,306 Bbl of oil per day, as compared to just over 3.3 million Bbl
of oil, or about 9,095 Bbl of oil per day, for the year ended December 31, 2014. This increased oil production was
primarily a result of newly drilled and completed wells in the Delaware Basin, as well as from newly drilled and
completed wells in the Eagle Ford shale in early 2015. Our natural gas revenues decreased $2.7 million, or a
decrease of 3%, to $75.0 million for the year ended December 31, 2015, as compared to $77.7 million for the year
ended December 31, 2014. The decrease in natural gas revenues resulted from a lower weighted average natural
gas price realized for the year ended December 31, 2015 of $2.71 per Mcf, as compared to $5.08 per Mcf realized
for the year ended December 31, 2014. The lower weighted average natural gas price was partially mitigated by
the 81% increase in our natural gas production to 27.7 Bcf for the year ended December 31, 2015, as compared to
15.3 Bcf for the year ended December 31, 2014. The increased natural gas production was primarily attributable
to new, non-operated Haynesville shale wells completed and placed on production on our Elm Grove properties in
Northwest Louisiana during the latter half of 2014 and into 2015, but also included increased natural gas production
associated with our operations in the Delaware Basin and the Eagle Ford shale.

Third-party midstream services revenues. Our third-party midstream services revenues increased to $1.9 million,
or an increase of 54%, for the year ended December 31, 2015, as compared to $1.2 million for the December 31, 2014.
The increase was primarily attributable to third-party oil, natural gas and salt water gathering and salt water disposal
fees in our Wolf asset area.

Realized gain (loss) on derivatives. Our realized net gain on derivatives was $77.1 million for the year ended
December 31, 2015, as compared to a realized net gain of $5.0 million for the year ended December 31, 2014. We
realized net gains of $62.3 million, $12.7 million and $2.2 million from our oil, natural gas and NGL derivative contracts,
respectively, for the year ended December 31, 2015 resulting from oil and natural gas prices being below the ﬂoor
prices of most of our costless collar contracts and NGL prices being below the ﬁxed prices of all of our swap

FORM 10-K PART I I

2016 ANNUAL REPORT

contracts. Our realized net gain on derivatives was $5.0 million for the year ended December 31, 2014. We realized
a net gain from our oil derivative contracts of approximately $5.2 million and a net gain of $0.5 million from
our NGL derivative contracts for the year ended December 31, 2014 due to oil prices being below the ﬂoor prices
of some of our oil costless collar contracts and NGL prices being below the ﬁxed prices of some of our swap
contracts, respectively, especially during the latter part of 2014. These gains were partially offset by a net loss of
$0.7 million on our natural gas derivative contracts, due to natural gas prices being in excess of the ceiling prices
of our natural gas costless collar contracts, especially in the early months of 2014. We realized an average gain of
approximately $22.89 per Bbl hedged on all of our open oil costless collar contracts during the year ended
December 31, 2015, as compared to an average gain of $2.00 per Bbl hedged for the year ended December 31, 2014.
Our oil volumes hedged for the year ended December 31, 2015 were also 5% higher as compared to the year
ended December 31, 2014. We realized an average gain of approximately $0.73 per MMBtu hedged on all of our
open natural gas costless collar contracts during the year ended December 31, 2015, as compared to an average
loss of approximately $0.06 per MMBtu hedged on all of our open natural gas costless collar contracts during the
year ended December 31, 2014. Our total natural gas volumes hedged for the year ended December 31, 2015
were also 38% higher than the total natural gas volumes hedged for the year ended December 31, 2014.

Unrealized gain (loss) on derivatives. Our unrealized net loss on derivatives was approximately $39.3 million
for the year ended December 31, 2015, as compared to an unrealized net gain of approximately $58.3 million for the
year ended December 31, 2014. During the year ended December 31, 2015, the net fair value of our open oil,
natural gas and NGL derivatives contracts decreased to approximately $16.3 million from $55.5 million for the year
ended December 31, 2014, resulting in an unrealized net loss on derivatives of approximately $39.3 million for the
year ended December 31, 2015. During the year ended December 31, 2015, the net fair value of our open oil,
natural gas and NGL derivative contracts decreased by $31.9 million, $5.4 million and $1.9 million, respectively, due
primarily to the realized gains from oil, natural gas and NGL derivative contracts settled during the year ended
December 31, 2015.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

EXPENSES

The following table summarizes our operating expenses and other income (expense) for the periods indicated.

(In thousands, except expenses per BOE)

Expenses:

Operating (loss) income
Other income (expense):

Net gain on asset sales and inventory impairment
Interest expense
Other (expense) income (3)
Total other income (expense)
(Loss) income before income taxes
Total income tax (beneﬁt) provision
Net (income) loss attributable to non-controlling interest in subsidiaries
Net (loss) income attributable to Matador Resources Company shareholders
Expenses per BOE:

Production taxes, transportation and processing (1)
Lease operating (2)
Plant and other midstream services operating
Depletion, depreciation and amortization
General and administrative

Year Ended December 31,

2016

2015

2014

$ 43,046
56,202
5,389
122,048
1,182
158,633
55,089
441,589
(177,167)

107,277
(28,199)
(4)
79,074
(98,093)
(1,036)
(364)
$ (97,421)

35,650
54,704
3,489
178,847
734
801,166
50,105
1,124,695
(806,662)

908
(21,754)
616
(20,230)
(826,892)
(147,368)
(261)
$ (679,785)

$
$
$
$
$

4.23
5.52
0.53
11.99
5.41

$
$
$
$
$

3.91
6.01
0.38
19.63
5.50

$ 33,172
49,945
1,408
134,737
504
—
32,152
251,918
180,331

—
(5,334)
132
(5,202)
175,129
64,375
17
$110,771

$
$
$
$
$

5.65
8.51
0.24
22.95
5.48

(1) $0.1 million, or $0.01 per BOE, was reclassiﬁed to third-party midstream revenues for the year ended December 31, 2015, due to our midstream

business becoming a reportable segment in the third quarter of 2016. There was no such reclassiﬁcation made in 2014.

(2) $3.5 million, or $0.38 per BOE, and $1.4 million, or $0.24 per BOE, were reclassiﬁed to plant and other midstream services operating expenses
for the years ended December 31, 2015 and 2014, respectively, due to our midstream business becoming a reportable segment in the third
quarter of 2016.

(3) $1.7 million and $1.2 million were reclassiﬁed to midstream services revenues for the years ended December 31, 2015 and 2014, respectively,

due to our midstream business becoming a reportable segment in the third quarter of 2016.

Year Ended December 31, 2016 as Compared to Year Ended December 31, 2015

Production taxes, transportation and processing. Our production taxes, transportation and processing expenses

increased $7.4 million to $43.0 million, an increase of 21%, for the year ended December 31, 2016, as compared
to $35.7 million for the year ended December 31, 2015. On a unit-of-production basis, our production taxes,
transportation and processing expenses increased 8% to $4.23 per BOE for the year ended December 31, 2016,
as compared to $3.91 per BOE for the year ended December 31, 2015. The increase in production taxes,
transportation and processing expenses was primarily attributable to higher transportation and processing expenses
of $26.5 million for the year ended December 31, 2016, as compared to transportation and processing expenses
of $22.4 million for the year ended December 31, 2015. This increase of $4.1 million was primarily due to the
increase in natural gas production in the Delaware Basin as a percentage of our total natural gas production for the
year ended December 31, 2016, as compared to the year ended December 31, 2015. Natural gas transportation and
processing expenses are higher in the Delaware Basin, as compared to the Eagle Ford shale, as the natural gas
gathering and processing infrastructure has yet to meet the demand for these services due to the increased drilling

FORM 10-K PART I I

2016 ANNUAL REPORT

activity in the Delaware Basin over the last few years. We have begun to incur lower processing expenses for most
of the natural gas produced in our Rustler Breaks asset area in Eddy County, New Mexico due to the start up in late
August 2016 of the Black River Processing Plant, and we expect to fully realize the impact of these lower processing
expenses once the plant is operational for an entire year.

Our production taxes increased $3.4 million to $16.6 million for the year ended December 31, 2016, as compared

to $13.2 million for the year ended December 31, 2015, primarily due to the 5% increase in oil and natural gas
revenues for the year ended December 31, 2016, as compared to the year ended December 31, 2015. In addition
to the increase in production taxes attributable to the 5% increase in oil and natural gas revenues, the production
tax rates in New Mexico are higher than production tax rates in Texas. As more of our oil and natural gas production
shifts from Texas to New Mexico, we expect to continue to experience increased production tax expenses.

Lease operating expenses. Our lease operating expenses increased $1.5 million to $56.2 million, an increase of
3%, for the year ended December 31, 2016, as compared to $54.7 million for the year ended December 31, 2015.
Our lease operating expenses per unit of production decreased 8% to $5.52 per BOE for the year ended
December 31, 2016, as compared to $6.01 per BOE for the year ended December 31, 2015. Our total oil and natural
gas production increased 12% to approximately 10.2 million BOE for the year ended December 31, 2016 from
approximately 9.1 million BOE for the year ended December 31, 2015. The decrease achieved in lease operating
expenses on a unit-of-production basis was primarily attributable to several key factors, including (i) decreased ﬁeld
supervisory costs as a number of third-party contractors became full-time employees during the second quarter of
2016, (ii) decreased costs associated with our Eagle Ford operations, including supervisory, salt water disposal
and chemical costs and (iii) increased oil equivalent production as compared to the year ended December 31, 2015.
This decrease was partially offset by (x) increased salt water disposal costs attributable to increased operations in
the Rustler Breaks asset area and (y) increased workover expenses in the Wolf asset area.

Plant and other midstream services operating. Our plant and other midstream services operating expenses
increased $1.9 million to $5.4 million, an increase of 54%, for the year ended December 31, 2016, as compared to
$3.5 million for the year ended December 31, 2015. This increase was primarily attributable to the expenses
associated with our salt water disposal operations of $3.6 million for the year ended December 31, 2016, as compared
to $2.2 million for the year ended December 31, 2015. The remaining increase was primarily attributable to expenses
associated with the Black River Processing Plant that began operating in August 2016.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses decreased

$56.8 million to $122.0 million, a decrease of 32%, for the year ended December 31, 2016, as compared to
$178.8 million for the year ended December 31, 2015. On a unit-of-production basis, our depletion, depreciation and
amortization expenses decreased 39% to $11.99 per BOE for the year ended December 31, 2016, as compared to
$19.63 per BOE for the year ended December 31, 2015. The decrease in our total depletion, depreciation and
amortization expenses resulted primarily from (i) higher total proved reserves of 105.8 million BOE, or an increase of
24%, at December 31, 2016, as compared to total proved reserves of 85.1 million BOE at December 31, 2015,
(ii) the decreased cost on a unit-of-production basis associated with wells drilled in 2016, as compared to prior
periods and (iii) the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded
in 2015 and 2016. This increase in total proved oil and natural gas reserves was primarily attributable to the
continued delineation and development of our acreage in the Delaware Basin.

Full-cost ceiling impairment. Due primarily to the continued decline in oil and natural gas prices during the ﬁrst

half of 2016, the net capitalized costs of our oil and natural gas properties less related deferred income taxes
exceeded the cost center ceiling. As a result, we recorded an impairment charge of $158.6 million, exclusive of tax
effect, for the year ended December 31, 2016 to our net capitalized costs. This charge is reﬂected in our statement
of operations for the year ended December 31, 2016, with the related deferred income tax credit recorded net of
a valuation allowance. These full-cost impairment charges for the year ended December 31, 2016 were realized in

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

the ﬁrst two quarters of the year. Since that time, oil and natural gas prices have improved and as a result, no
full-cost ceiling impairment charges were recorded in the third and fourth quarters of 2016.

Due primarily to the sharp decline in oil and natural gas prices during 2015, at December 31, 2015, the net
capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center
ceiling. As a result, we recorded an impairment charge of $801.2 million, exclusive of tax effect, to our net
capitalized costs. This charge is reﬂected in our statement of operations for the year ended December 31, 2015,
with the related deferred income tax credit recorded net of a valuation allowance.

General and administrative. Our general and administrative expenses increased $5.0 million to $55.1 million,

an increase of 10%, for the year ended December 31, 2016, as compared to $50.1 million for the year ended
December 31, 2015. The increase in our general and administrative expenses was primarily attributable
to increased payroll expenses associated with additional employees joining the Company during the year ended
December 31, 2016 to support our increased land, geoscience, drilling, completion, production, midstream,
accounting and administration functions as a result of the continued growth of the Company. The remaining
increase is largely due to a $2.9 million increase in non-cash stock-based compensation expense to $12.4 million
for the year ended December 31, 2016, as compared to $9.5 million for the year ended December 31, 2015.
The increase in our non-cash stock-based compensation expense was attributable to the increased expense related
to the continued vesting of awards granted from 2012 through 2016. Our general and administrative expenses
decreased 2% on a unit-of-production basis to $5.41 per BOE for the year ended December 31, 2016, as compared
to $5.50 per BOE for the year ended December 31, 2015.

Net gain on asset sales and inventory impairment. We recorded a net gain of $107.3 million on asset sales

and inventory impairment for the year ended December 31, 2016, as compared to $0.9 million for the year ended
December 31, 2015. On October 1, 2015, we completed the sale of our wholly-owned subsidiary that owned the
Loving County Processing System to EnLink. The Loving County Processing System included the Wolf Processing
Plant and approximately six miles of high pressure gathering pipeline that connects our natural gas gathering system
to the Wolf Processing Plant.

Pursuant to the terms of the transaction, EnLink paid approximately $143.4 million and we received net proceeds
of approximately $139.8 million, after deducting customary purchase price adjustments of approximately $3.6 million.
Due to the terms of the Wolf Gathering Agreement, the transaction was accounted for as a sale and leaseback
transaction; the carrying value of the net assets sold of approximately $31.0 million was removed from the
consolidated balance sheet as of December 31, 2015 and the resulting difference of approximately $108.4 million
between the net proceeds received less closing costs of $0.4 million and the basis of the assets sold was
recorded as a deferred gain on plant sale and was to be recognized as a gain on asset sales over the 15-year
term of the gathering and processing agreement. See Note 13 to the consolidated ﬁnancial statements in this
Annual Report for more information on this agreement.

During the fourth quarter of 2016, EnLink completed construction of another processing plant in Loving County,

Texas. Upon completion and successful testing of the new plant, EnLink began processing our natural gas at the
new plant. As such, the gathering and processing agreement is no longer considered a lease, and accordingly the
Company recognized the remaining unamortized gain on the sale of $107.3 million in the consolidated statement
of operations for the year ended December 31, 2016.

Interest expense. For the year ended December 31, 2016, we incurred total interest expense of approximately
$31.9 million. We capitalized approximately $3.7 million of our interest expense on certain qualifying projects for the
year ended December 31, 2016 and expensed the remaining $28.2 million to operations. For the year ended
December 31, 2015, we incurred total interest expense of approximately $25.7 million. We capitalized approximately
$3.9 million of our interest expense on certain qualifying projects for the year ended December 31, 2015 and

FORM 10-K PART I I

2016 ANNUAL REPORT

expensed the remaining $21.8 million to operations. The increase in total interest expense of $6.2 million for the
year ended December 31, 2016, as compared to the year ended December 31, 2015, was attributable to an
increase in both the average debt outstanding and the coupon rate of 6.875% for the senior notes issued in 2015
and late 2016, as compared to the lower effective interest rates incurred on borrowings under our Credit Agreement.
In December 2016, we used a portion of the net proceeds from the December 2016 senior notes and equity
offerings to repay a total of $120.0 million of outstanding borrowings under our Credit Agreement. At December 31,
2016, we had no outstanding borrowings under our Credit Agreement, $0.8 million in outstanding letters of credit
and $575.0 million in outstanding senior notes. Due to the higher coupon rate on the senior notes as compared to
the interest rates under the Credit Agreement, we expect to incur increased interest expense in future periods.

Total income tax (beneﬁt) provision. Our deferred tax assets exceeded our deferred tax liabilities at December 31,

2016 due to the deferred tax amounts generated by the full-cost ceiling impairment charges recorded in 2016 and
2015. As a result, we established a valuation allowance against the deferred tax assets beginning in the third quarter
of 2015. We retained a full valuation allowance at December 31, 2016 due to uncertainties regarding the future
realization of our deferred tax assets. The current tax beneﬁt of $1.0 million for the year ended December 31, 2016
was primarily attributable to a refund due from the Internal Revenue Service. The total income tax expense for
the year ended December 31, 2016 differed from amounts computed by applying the U.S. federal statutory tax rate
to the pre-tax loss due primarily to the recording of a valuation allowance against the net deferred tax asset position
as a result of the full-cost ceiling impairments recorded for the years ended December 31, 2016 and 2015.

Year Ended December 31, 2015 as Compared to Year Ended December 31, 2014

Production taxes, transportation and processing. Our production taxes, transportation and processing expenses
increased by $2.5 million to $35.7 million, an increase of 7%, for the year ended December 31, 2015, as compared
to $33.2 million for the year ended December 31, 2014. On a unit-of-production basis, however, our production
taxes and marketing expenses decreased by 31% to $3.91 per BOE for the year ended December 31, 2015, as
compared to $5.65 per BOE for the year ended December 31, 2014. The increase in production taxes, transportation
and processing expenses on an absolute basis was primarily attributable to higher natural gas transportation
and processing expenses of $22.4 million for the year ended December 31, 2015, as compared to natural gas
transportation and processing expenses of $15.2 million for the year ended December 31, 2014, an increase of
$7.2 million, due to the 81% increase in our natural gas production to 27.7 Bcf for the year ended December 31,
2015, as compared to 15.3 Bcf of natural gas production for the year ended December 31, 2014. This increase was
partially offset by a decrease in our production taxes of $4.8 million to $13.2 million for the year ended December 31,
2015, as compared to $18.0 million for the year ended December 31, 2014, primarily due to the 30% decrease in
oil revenues for the year ended December 31, 2015, as compared to the year ended December 31, 2014.

Lease operating expenses. Our lease operating expenses increased by $4.8 million to $54.7 million, an increase

of 10%, for the year ended December 31, 2015, as compared to $49.9 million for the year ended December 31,
2014. Our lease operating expenses per unit of production decreased 29% to $6.01 per BOE for the year ended
December 31, 2015, as compared to $8.51 per BOE for the year ended December 31, 2014. Our total oil and natural
gas production increased 55% to approximately 9.1 million BOE for the year ended December 31, 2015 from
approximately 5.9 million BOE for the year ended December 31, 2014, including an increase of 35% in oil production
to approximately 4.5 million Bbl for the year ended December 31, 2015, as compared to just over 3.3 million Bbl for
the year ended December 31, 2014, which would typically result in higher lease operating expenses. Oil production
was 49% of total production by volume for the year ended December 31, 2015, as compared to 57% of total
production by volume for the year ended December 31, 2014. The decrease achieved in lease operating expenses
on a unit-of-production basis was primarily attributable to several key factors, including (i) no clean-out operations
on offsetting producing wells as a result of fracturing operations on newly drilled Eagle Ford shale wells as
compared to the same period in 2014, (ii) a decrease in salt water disposal costs on a per barrel basis, particularly
in the Delaware Basin, (iii) reduced service costs impacting lease operating expenses and (iv) a higher percentage of

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

natural gas production, including a signiﬁcant increase in Haynesville natural gas production, which typically has
lower operating costs due to its lack of associated oil and water production. A joint venture controlled by us drilled,
completed and began injecting salt water into a new disposal well in the Wolf asset area in Loving County, Texas
in January 2015, which reduced salt water disposal costs in this area. A second salt water disposal well was drilled
and tested in the Wolf asset area and began disposing of salt water in the fourth quarter of 2015. At December 31,
2015, this well was operating with temporary facilities, but it became fully operational with permanent facilities in
the ﬁrst quarter of 2016.

Plant and other midstream services operating. Our plant and other midstream services operating expenses
increased by $2.1 million to $3.5 million, an increase of 148%, for the year ended December 31, 2015, as compared
to $1.4 million for the year ended December 31, 2014. This increase was primarily attributable to the expenses
associated with our salt water disposal facilities in our Wolf asset area, which began operations in early 2015.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased

by $44.1 million to $178.8 million, an increase of 33%, for the year ended December 31, 2015, as compared
to $134.7 million for the year ended December 31, 2014. On a unit-of-production basis, however, our depletion,
depreciation and amortization expenses decreased 15% to $19.63 per BOE for the year ended December 31, 2015,
as compared to $22.95 per BOE for the year ended December 31, 2014. The absolute increase in our depletion,
depreciation and amortization expenses reﬂected an increase of 55% in our total oil and natural gas production to
9.1 million BOE for the year ended December 31, 2015 from 5.9 million BOE for the year ended December 31, 2014.
The 15% decrease in the per-unit-of-production depletion, depreciation and amortization expenses resulted
from the 24% increase in total proved oil and natural gas reserves from 68.7 million BOE at December 31, 2014
to 85.1 million BOE at December 31, 2015, which reserves were added at a lower cost per BOE, as well as
from the decrease in unamortized property costs resulting from the full-cost ceiling impairments recorded in 2015.

Full-cost ceiling impairment. Due primarily to the sharp decline in oil and natural gas prices during 2015, at
December 31, 2015, the net capitalized costs of our oil and natural gas properties less related deferred income taxes
exceeded the cost center ceiling. As a result, we recorded an impairment charge of $801.2 million, exclusive of
tax effect, to our net capitalized costs. This charge is reﬂected in our statement of operations for the year ended
December 31, 2015, with the related deferred income tax credit recorded net of a valuation allowance. No
impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from
a full-cost ceiling impairment was recorded during the year ended December 31, 2014.

General and administrative. Our general and administrative expenses increased by $18.0 million to $50.1 million,

an increase of 56%, for the year ended December 31, 2015, as compared to $32.2 million for the year ended
December 31, 2014. The increase in our general and administrative expenses was primarily attributable to increased
payroll expenses associated with additional personnel joining the Company during the year ended December 31, 2015
to support our increased land, geoscience, drilling, completion, production, accounting and administration functions,
including the addition of 29 new employees in Roswell, New Mexico as a result of the HEYCO Merger in late
February 2015. The remaining increase is largely due to a $4.0 million increase in non-cash stock-based compensation
expense to $9.5 million for the year ended December 31, 2015, as compared to $5.5 million for the year ended
December 31, 2014. The increase in our non-cash stock-based compensation expense was attributable to the
increased expense related to the continued vesting of awards granted from 2012 through 2015 of $9.5 million for
the year ended December 31, 2015, as compared to $5.3 million for the year ended December 31, 2014. This
increase was partially offset by the decreased expense related to our liability-based stock options of $0.1 million for
the year ended December 31, 2015, as compared to $0.2 million for the year ended December 31, 2014. This
decreased expense related to our liability-based stock options was attributable to the slight decrease in our stock
price from $20.23 per share at December 31, 2014 to $19.77 per share at December 31, 2015. Our general and
administrative expenses increased by less than 1% on a unit-of-production basis to $5.50 per BOE for the year
ended December 31, 2015, as compared to $5.48 per BOE for the year ended December 31, 2014.

FORM 10-K PART I I

2016 ANNUAL REPORT

Interest expense. For the year ended December 31, 2015, we incurred total interest expense of approximately
$25.7 million. We capitalized approximately $3.9 million of our interest expense on certain qualifying projects for the
year ended December 31, 2015 and expensed the remaining $21.8 million to operations. For the year ended
December 31, 2014, we incurred total interest expense of approximately $8.2 million. We capitalized approximately
$2.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2014 and
expensed the remaining $5.3 million to operations. The increase in total interest expense of $17.5 million for the
year ended December 31, 2015, as compared to the year ended December 31, 2014, was attributable to an
increase in both the average debt outstanding and the interest rate of 6.875% under the senior notes in 2015, as
compared to the effective interest rate of approximately 3.3% under our Credit Agreement in 2014. In late April
2015, we used a portion of the net proceeds from the April 2015 senior notes and equity offerings to repay a total of
$465.0 million of outstanding borrowings under our Credit Agreement. At December 31, 2015, we had no
outstanding borrowings under our Credit Agreement, $0.6 million in outstanding letters of credit and $400.0 million
in outstanding senior notes.

Total income tax (beneﬁt) provision. At December 31, 2015, our deferred tax assets exceeded our deferred
tax liabilities and, as a result, we recorded a valuation allowance of $154.3 million against the deferred tax assets.
The total income tax expense for the year ended December 31, 2015 differed from amounts computed by applying
the U.S. federal statutory tax rates to the pre-tax loss due primarily to the recording of a valuation allowance against
the net deferred tax asset position as a result of the full-cost ceiling impairment recorded for the year ended
December 31, 2015. We recorded a total income tax beneﬁt of $147.4 million for the year ended December 31, 2015.
The total income tax beneﬁt of $147.4 million for the year ended December 31, 2015 is comprised of a current tax
expense of $3.0 million, which represented our estimated alternative minimum tax (“AMT”) liability, and a deferred
tax beneﬁt of $150.3 million. For the year ended December 31, 2014, we incurred an estimated AMT liability of
$0.1 million, which represented the current portion of the income tax provision. The remaining income tax provision
of $64.2 million represented deferred taxes for the year ended December 31, 2014. Our effective tax rate for the
year ended December 31, 2014 was 36.8%. Total income tax expense for the year ended December 31, 2014
differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily due
to the impact of permanent differences between book and taxable income.

LIQUIDITY AND CAPITAL RESOURCES

Our primary use of capital has been, and we expect will continue to be during 2017 and for the foreseeable

future, for the acquisition, exploration and development of oil and natural gas properties and for midstream
investments. Excluding any possible signiﬁcant acquisitions, we expect to fund our capital expenditure requirements
through 2017 through a combination of cash on hand, operating cash ﬂows, proceeds we received in connection
with the formation of the Joint Venture and borrowings under our Credit Agreement (assuming availability under our
borrowing base). We continually evaluate other capital sources, including borrowings under additional credit
arrangements, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage,
particularly in our non-core asset areas, as well as potential issuances of equity, debt or convertible securities, none
of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and
production will be highly dependent on our ability to access outside sources of capital and to generate operating
cash ﬂows.

At December 31, 2016, we had cash totaling approximately $212.9 million and restricted cash totaling

approximately $1.3 million. Restricted cash represents cash held by our less-than-wholly-owned subsidiaries. By
contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be
commingled with other Company cash and is to be used only to fund the capital expenditures and operations of
these less-than-wholly-owned subsidiaries.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

On October 31, 2016, the lenders party to our Credit Agreement increased our borrowing base from

$300.0 million to $400.0 million. At December 31, 2016 and February 22, 2017, the borrowing base under our Credit
Agreement remained $400.0 million. At both dates, we had no outstanding borrowings and approximately
$0.8 million in outstanding letters of credit under the Credit Agreement, and we had $575.0 million of outstanding
senior notes.

On March 11, 2016, we completed a public offering of 7,500,000 shares of common stock (the “March Equity

Offering”). After deducting offering costs totaling approximately $0.8 million, we received net proceeds of
approximately $141.5 million. We used the net proceeds for general corporate purposes, including to fund a portion
of our capital expenditures.

On December 9, 2016, we completed a public offering of 6,000,000 shares of common stock (the “December

Equity Offering” and, together with the March Equity Offering, the “2016 Equity Offerings”). After deducting
offering costs totaling approximately $0.4 million, we received net proceeds of approximately $145.8 million.

On December 9, 2016, we issued $175.0 million of 6.875% senior notes due 2023 (the “Additional Notes”) in a

private placement (the “Notes Offering”). The Additional Notes were issued pursuant to the same indenture
governing the Company’s original senior notes issued in April 2015 and were issued at 105.5% of par, plus accrued
interest from October 15, 2016, resulting in an effective interest rate of 5.5%. We received net proceeds from
the Notes Offering of approximately $181.5 million, including the issue premium, but after deducting the initial
purchasers’ discounts and estimated offering expenses and excluding accrued interest paid by buyers of
the Additional Notes. The Additional Notes are our senior unsecured obligations. The Additional Notes mature on
April 15, 2023, and interest is payable semi-annually in arrears on April 15 and October 15 of each year.

We have used a portion of the net proceeds from the Notes Offering and the December Equity Offering to fund

the aggregate purchase price for certain leasehold and mineral acquisitions (some of which closed in January and
February 2017) and further development of our midstream assets, to repay $120.0 million in outstanding borrowings
under our Credit Agreement and for general corporate purposes, including capital expenditures associated with
the addition of a fourth drilling rig.

On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with a subsidiary of

We expect that development of our Delaware Basin assets will be the primary focus of our operations and

capital expenditures in 2017. We plan to operate four contracted drilling rigs in the Delaware Basin during the ﬁrst
quarter of 2017 and expect to add a ﬁfth drilling rig in the Delaware Basin in the second quarter of 2017. Our 2017
estimated capital expenditure budget consists of $370 to $390 million for drilling, completions, facilities and
infrastructure and $56 to $64 million for midstream capital expenditures, which represents our 51% share of an
estimated 2017 capital expenditure budget of $110 to $125 million for San Mateo. Substantially all of our 2017
estimated capital expenditures will be allocated to the further delineation and development of our growing leasehold
position and midstream assets in the Delaware Basin, with the exception of amounts allocated to limited operations
in the Eagle Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated
well opportunities. Our 2017 Delaware Basin drilling program will focus on the continued development of the Wolf
and Rustler Breaks asset areas and the further delineation and development of the Jackson Trust, Ranger/
Arrowhead and Twin Lakes asset areas, although we do anticipate continuing to delineate previously untested zones
in the Wolf and Rustler Breaks asset areas during 2017.

FORM 10-K PART I I

2016 ANNUAL REPORT

We intend to continue acquiring acreage and mineral interests, principally in the Delaware Basin, during 2017.

These expenditures are opportunity-speciﬁc and per-acre prices can vary signiﬁcantly based on the prospect. As a
result, it is difﬁcult to estimate these 2017 capital expenditures with any degree of certainty; therefore, we have not
provided estimated capital expenditures related to acreage and mineral acquisitions for 2017.

From January 1 through February 22, 2017, we acquired approximately 13,900 gross (8,200 net) leasehold and
mineral acres and approximately 1,000 BOE per day of related production from various lessors and other operators,
mostly in and around our existing acreage in the Delaware Basin. As noted above, some of this acreage and a
portion of the production included properties identiﬁed at the time of the Notes Offering and the December Equity
Offering. These transactions were pending at the time of those offerings and closed subsequent to December 31,
2016, bringing our total Permian Basin acreage position at February 22, 2017 to 177,600 gross (101,400 net) acres,
almost all of which was located in the Delaware Basin. We have incurred capital expenditures of approximately
$111 million since January 1, 2017 to acquire leasehold and mineral interests and the related production.

Our 2017 capital expenditures may be adjusted as business conditions warrant and the amount, timing and

allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital
we will expend may ﬂuctuate materially based on market conditions, the actual costs to drill, complete and place
on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream
activities, including the expansion of the Black River Processing Plant, the ability of our Joint Venture partner to
meet its capital obligations, other opportunities that may become available to us and our ability to obtain capital.
When oil or natural gas prices decline, or costs increase signiﬁcantly, we have the ﬂexibility to defer a signiﬁcant
portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe
have the highest expected returns and potential to generate near-term cash ﬂows. We routinely monitor and adjust
our capital expenditures in response to changes in prices, availability of ﬁnancing, drilling, completion and acquisition
costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success
in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate
and other factors both within and outside our control.

Exploration and development activities are subject to a number of risks and uncertainties, which could cause
these activities to be less successful than we anticipate. A signiﬁcant portion of our anticipated cash ﬂows from
operations for 2017 is expected to come from producing wells and development activities on currently proved
properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and
the Haynesville shale in Louisiana. Our existing wells may not produce at the levels we are forecasting and our
exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our
anticipated cash ﬂows from operations are based upon current expectations of oil and natural gas prices for 2017
and the hedges we currently have in place. We use commodity derivative ﬁnancial instruments at times to
mitigate our exposure to ﬂuctuations in oil, natural gas and natural gas liquids prices and to partially offset reductions
in our cash ﬂows from operations resulting from declines in commodity prices. As of February 22, 2017, we had
approximately 70% of our anticipated oil production and approximately 50% of our anticipated natural gas
production hedged for 2017. We have no hedges in place for natural gas liquids and no hedges in place for natural
gas beyond 2017; however, we have a portion of our anticipated oil production volumes hedged in 2018. See Note 8
to the consolidated ﬁnancial statements in this Annual Report for a summary of our open derivative ﬁnancial
instruments at December 31, 2016. See “Risk Factors — Our Exploration, Development and Exploitation Projects
Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential
Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect
Our Future Growth,” “Risk Factors — Drilling for and Producing Oil and Natural Gas Are Highly Speculative and
Involve a High Degree of Operational and Financial Risk, with Many Uncertainties That Could Adversely Affect Our
Business” and “Risk Factors — Our Identiﬁed Drilling Locations Are Scheduled over Several Years, Making Them
Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.”

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

Our cash ﬂows for the years ended December 31, 2016, 2015 and 2014 are presented below.

(In thousands)

Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by ﬁnancing activities
Net change in cash

Cash Flows Provided by Operating Activities

Year Ended December 31,

2016

2015

2014

$ 134,086

$ 208,535

(405,640)
467,706
$ 196,152

(425,154)
224,944
8,325

$ 251,481
(570,531)
321,170
2,120

Net cash provided by operating activities decreased $74.4 million to $134.1 million for the year ended

December 31, 2016, as compared to net cash provided by operating activities of $208.5 million for the year ended
December 31, 2015. Excluding changes in operating assets and liabilities, net cash provided by operating activities
decreased to $132.3 million for the year ended December 31, 2016 from $199.6 million for the year ended
December 31, 2015. This decrease was primarily attributable to the decrease in our realized gain on derivatives,
which declined by $67.8 million to $9.3 million for the year ended December 31, 2016, as compared to $77.1 million
for the year ended December 31, 2015. Changes in our operating assets and liabilities between December 31, 2015
and December 31, 2016 also resulted in a net decrease of approximately $7.2 million in net cash provided by
operating activities for the year ended December 31, 2016, as compared to the year ended December 31, 2015.

Net cash provided by operating activities decreased by $42.9 million to $208.5 million for the year ended

December 31, 2015, as compared to net cash provided by operating activities of $251.5 million for the year ended
December 31, 2014. Excluding changes in operating assets and liabilities, net cash provided by operating activities
decreased to $199.6 million for the year ended December 31, 2015 from $257.5 million for the year ended
December 31, 2014. This decrease was primarily attributable to the decrease in oil revenues from 2014 to 2015,
resulting from a signiﬁcantly lower weighted average oil price realized for the year ended December 31, 2015 of
$45.27 per Bbl, as compared to $87.37 per Bbl realized for the year ended December 31, 2014. This decrease was
partially offset by the increase of 35% in our oil production to approximately 4.5 million Bbl from just over 3.3 million
Bbl during the respective periods. Changes in our operating assets and liabilities between December 31, 2014 and
December 31, 2015 also resulted in a net increase of approximately $15.0 million in net cash provided by operating
activities for the year ended December 31, 2015, as compared to the year ended December 31, 2014.

Our operating cash ﬂows are sensitive to a number of variables, including changes in our production and the

volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the
actions of OPEC, weather, infrastructure capacity to reach markets and other variable factors signiﬁcantly impact the
prices of oil and natural gas. These factors are beyond our control and are difﬁcult to predict. We use commodity
derivative ﬁnancial instruments to mitigate our exposure to ﬂuctuations in oil, natural gas and natural gas liquids prices.
In addition, we attempt to avoid long-term service agreements in order to minimize ongoing future commitments.
For additional information on the impact of changing prices on our ﬁnancial condition, see “Quantitative and Qualitative
Disclosures About Market Risk.” See also “Risk Factors — Our Success Is Dependent on the Prices of Oil and
Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our
Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.”

Cash Flows Used in Investing Activities

Net cash used in investing activities decreased $19.5 million to $405.6 million for the year ended December 31,

2016 from $425.2 million for the year ended December 31, 2015. This decrease in net cash used in investing
activities included (i) a decrease of $53.6 million in oil and natural gas properties capital expenditures for the year
ended December 31, 2016, as compared to the year ended December 31, 2015, (ii) an increase of approximately

FORM 10-K PART I I

2016 ANNUAL REPORT

$10.3 million in expenditures for other property and equipment, which includes the construction of the Black River
Processing Plant and new pipeline infrastructure, (iii) a decrease in cash used for acquisitions as the HEYCO
Merger occurred in 2015, (iv) a reduction in proceeds from sales of assets as the sale of the Loving County
Processing System to EnLink occurred in 2015 and (v) a decrease in our restricted cash of $43.7 million attributable
to the release from escrow of potential like-kind-exchange funds in connection with the sale of the Loving County
Processing System to EnLink. Cash used for oil and natural gas properties capital expenditures for the year ended
December 31, 2016 was primarily attributable to our operated and non-operated drilling and completion activities
in the Delaware Basin, as well as the acquisition of additional acreage and mineral interests in the Delaware Basin.

Net cash used in investing activities decreased by $145.4 million to $425.2 million for the year ended December 31,

2015 from $570.5 million for the year ended December 31, 2014. This decrease in net cash used in investing
activities included (i) a decrease of $128.1 million in our oil and natural gas properties capital expenditures for the
year ended December 31, 2015, as compared to the year ended December 31, 2014, (ii) proceeds from the sale
of the Loving County Processing System to EnLink of $139.8 million, (iii) an increase of approximately $55.3 million
in expenditures for other property and equipment, which includes the Wolf Processing Plant and salt water disposal
facilities we constructed in Loving County, Texas as well as initial costs associated with the Black River Processing
Plant and new pipeline infrastructure, (iv) cash used in the HEYCO Merger of $24.0 million and (v) an increase in our
restricted cash of $43.1 million attributable to the escrow account associated with potential like-kind-exchange
transactions in connection with the sale of the Loving County Processing System to EnLink. Cash used for oil and
natural gas properties capital expenditures for the year ended December 31, 2015 was primarily attributable to
our operated and non-operated drilling and completion activities in the Delaware Basin, as well as to our operated
and non-operated drilling activities in the Eagle Ford shale play and certain non-operated drilling activities in the
Haynesville shale.

Cash Flows Provided by Financing Activities

Net cash provided by ﬁnancing activities was $467.7 million for the year ended December 31, 2016, as compared

to net cash provided by ﬁnancing activities of $224.9 million for the year ended December 31, 2015. The net cash
provided by ﬁnancing activities for the year ended December 31, 2016 was primarily attributable to the total proceeds
of the 2016 Equity Offerings of $288.5 million, the total proceeds of the Notes Offering of $184.6 million and
borrowings under our Credit Agreement of $120.0 million, offset by the costs of the 2016 Equity Offerings of
$0.8 million, the costs of the Notes Offering of $2.7 million, the repayment of $120.0 million in borrowings under
our Credit Agreement in December 2016 and the payment of $1.9 million in taxes related to net share settlement of
stock-based compensation.

Net cash provided by ﬁnancing activities was $224.9 million for the year ended December 31, 2015, as compared

to net cash provided by ﬁnancing activities of $321.2 million for the year ended December 31, 2014. The net cash
provided by ﬁnancing activities for the year ended December 31, 2015 was primarily attributable to the total
proceeds of our April 2015 public equity offering of $188.7 million, total proceeds of our April 2015 notes offering of
$400.0 million, borrowings under our Credit Agreement of $125.0 million and capital contributed from the non-
controlling interest owners in our less-than-wholly-owned subsidiaries of $0.6 million, offset by the costs of the
equity offering of $1.2 million, the costs of the April 2015 notes offering of $9.6 million, the repayment of
$477.0 million in borrowings under our Credit Agreement during the period and the payment of $1.6 million in taxes
related to net share settlement of stock-based compensation.

Net cash provided by ﬁnancing activities was $321.2 million for the year ended December 31, 2014. The net cash

provided by ﬁnancing activities for the year ended December 31, 2014 was primarily attributable to the total
proceeds from our May 2014 public equity offering of $181.9 million and total borrowings of $320.0 million under
our Credit Agreement during the period, offset by the costs of the offering of $0.6 million incurred during the
period and by the repayment of $180.0 million in borrowings under our Credit Agreement during the period.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

See Note 6 to the consolidated ﬁnancial statements in this Annual Report for a summary of our debt, including

our Credit Agreement and the senior notes.

OFF-BALANCE SHEET ARRANGEMENTS

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material

off-balance sheet obligations of the Company. As of December 31, 2016, the material off-balance sheet
arrangements and transactions that we had entered into include (i) operating lease agreements, (ii) non-operated
drilling commitments, (iii) termination obligations under drilling rig contracts, (iv) ﬁrm transportation, gathering,
processing, disposal and fractionation commitments and (v) contractual obligations for which the ultimate settlement
amounts are not ﬁxed and determinable, such as derivative contracts that are sensitive to future changes in
commodity prices or interest rates, gathering, treating, fractionation and transportation commitments on uncertain
volumes of future throughput, open delivery commitments and indemniﬁcation obligations following certain
divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions,
arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to
materially affect the Company’s liquidity or availability of or requirements for capital resources. See “—Obligations
and Commitments” below and Note 13 to the consolidated ﬁnancial statements in this Annual Report for
more information regarding the Company’s off-balance sheet arrangements. Such information is incorporated
herein by reference.

OBLIGATIONS AND COMMITMENTS

We had the following material contractual obligations and commitments at December 31, 2016.

(In thousands)

Contractual Obligations:
Revolving credit borrowings, including letters of credit (1)
Senior unsecured notes (2)
Ofﬁce leases
Non-operated drilling commitments (3)
Drilling rig contracts (4)
Asset retirement obligations
Natural gas processing and transportation agreements (5)

Total contractual cash obligations

Payments Due by Period

Total

Less Than
1 Year

1-3 Years

3-5 Years

More Than
5 Years

821
575,000
25,063
11,053
46,295
20,641
12,877
$ 691,750

$ —
—
2,443
11,053
26,017
915
10,599
$ 51,027

$ —
—
5,023
—
20,278
982
2,278
$ 28,561

$ 821
—
5,262
—
—
558
—
$ 6,641

—
575,000
12,335
—
—
18,186
—
$ 605,521

At December 31, 2016, we had no borrowings outstanding under the Credit Agreement and approximately $0.8 million in outstanding letters of
credit issued pursuant to the Credit Agreement. The Credit Agreement matures in October 2020.

(2) The amounts included in the table above represent principal maturities only.

(3) At December 31, 2016, we had outstanding commitments to participate in the drilling and completion of various non-operated wells. Our

working interests in these wells are typically small, and certain of these wells were in progress at December 31, 2016. If all of these wells are
drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these wells of approximately
$11.1 million at December 31, 2016, which we expect to incur within the next year.

(4) We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 13 to the

consolidated ﬁnancial statements in this Annual Report for more information regarding these contractual commitments.

(5) Effective September 1, 2012, we entered into a ﬁrm ﬁve-year natural gas processing and transportation agreement for a signiﬁcant portion of our

operated natural gas production in South Texas. Effective October 1, 2015, we entered into a 15-year ﬁxed-fee natural gas gathering and
processing agreement for a signiﬁcant portion of our operated natural gas production in Loving County, Texas. See Note 13 to the consolidated
ﬁnancial statements in this Annual Report for more information regarding these contractual commitments.

FORM 10-K PART I I

2016 ANNUAL REPORT

GENERAL OUTLOOK AND TRENDS

Our business success and ﬁnancial results are dependent on many factors beyond our control, such as

economic, political and regulatory developments, as well as competition from other sources of energy. Commodity
price volatility, in particular, is a signiﬁcant risk to our business and results of operations. Commodity prices are
affected by changes in market supply and demand, which are impacted by overall economic activity, the actions of
OPEC, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and
other factors. Historically, the markets for oil, natural gas and natural gas liquids have been volatile and these markets
will likely continue to be volatile in the future. Prices for oil, natural gas and natural gas liquids affect the cash ﬂows
available to us for capital expenditures and our ability to borrow and raise additional capital. Declines in oil, natural
gas or natural gas liquids prices not only reduce our revenues, but could also reduce the amount of oil, natural gas
and/or natural gas liquids that we can produce economically, and as a result, could have an adverse effect on our
ﬁnancial condition, results of operations, cash ﬂows and reserves. From time to time, we use derivative ﬁnancial
instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and natural gas liquids
prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difﬁcult and
depend on market conditions and our forecast of future production and oil, natural gas and natural gas liquids prices,
and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be
accessed through the borrowing base under our Credit Agreement and through the capital markets. See “Risk
Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the
Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our
Capital Expenditure Requirements and Financial Obligations.”

In 2016, oil and natural gas prices remained signiﬁcantly below their most recent highs in 2014, although

commodity prices did begin to improve in the latter half of 2016. Oil prices had increased to $54.06 per Bbl in late
December 2016 from $37.04 on December 31, 2015, and natural gas prices had increased to $3.93 per MMBtu in
late December 2016 from $2.34 per MMBtu on December 31, 2015. The sharp declines in oil and natural gas prices
since late 2014 have impacted our revenues, proﬁtability and cash ﬂows in 2015 and 2016, as compared to 2014,
and additional declines in oil and natural gas prices could have an adverse impact on our borrowing capacity, ability
to obtain additional capital, revenues, proﬁtability and cash ﬂows. We are uncertain if oil and natural gas prices may
continue to rise from their current levels, and in fact, oil and natural gas prices may decrease again in future periods.

For the year ended December 31, 2016, oil prices averaged $43.40 per Bbl, ranging from a high of $54.06 per Bbl

in late December to a low of $26.21 per Bbl in mid-February, based upon the NYMEX West Texas Intermediate oil
futures contract price for the earliest delivery date. We realized a weighted average oil price of $41.19 per Bbl
($42.34 per Bbl including realized gains from oil derivatives) for our oil production for the year ended December 31,
2016, as compared to $45.27 per Bbl ($59.13 per Bbl including realized gains from oil derivatives) for the year
ended December 31, 2015. At February 24, 2017, the NYMEX West Texas Intermediate oil futures contract for the
earliest delivery date had remained fairly steady, closing at $53.99 per Bbl, as compared to $32.15 per Bbl at
February 24, 2016.

For the year ended December 31, 2016, natural gas prices averaged $2.55 per MMBtu, ranging from a high of

approximately $3.93 per MMBtu in late December to a low of approximately $1.64 per MMBtu in early March,
based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. We realized a
weighted average natural gas price of $2.66 per Mcf ($2.78 per Mcf including realized gains from natural gas
derivatives) for our natural gas production for the year ended December 31, 2016, as compared to $2.71 per Mcf
($3.24 per Mcf including realized gains from natural gas and NGL derivatives) for the year ended December 31,
2015. At February 24, 2017, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date had
declined from late December, closing at $2.63 per MMBtu, as compared to $1.78 per MMBtu at February 24, 2016.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital

expenditures in 2017. We plan to operate four contracted drilling rigs in the Delaware Basin during the ﬁrst quarter
of 2017, with a ﬁfth drilling rig added in the Delaware Basin in the second quarter of 2017. Our 2017 estimated
capital expenditure budget consists of $370 to $390 million for drilling, completions, facilities and infrastructure and
$56 to $64 million for midstream capital expenditures, which represents our 51% share of an estimated 2017
capital expenditure budget of $110 to $125 million for San Mateo. Substantially all of our 2017 estimated capital
expenditures will be allocated to the further delineation and development of our growing leasehold position
and midstream assets in the Delaware Basin, with the exception of amounts allocated to limited operations in the
Eagle Ford and Haynesville shales to maintain and extend leases and to participate in certain non-operated well
opportunities. Our 2017 Delaware Basin drilling program will focus on the continued development of the Wolf and
Rustler Breaks asset areas and the further delineation and development of the Jackson Trust, Ranger/Arrowhead
and Twin Lakes asset areas, although we do anticipate continuing to delineate previously untested zones in the Wolf
and Rustler Breaks asset areas during 2017.

We intend to continue acquiring acreage and mineral interests, principally in the Delaware Basin, during 2017.
These expenditures are opportunity-speciﬁc and per-acre prices can vary signiﬁcantly based on the prospect. As a
result, it is difﬁcult to estimate these 2017 capital expenditures with any degree of certainty; therefore, we have
not provided estimated capital expenditures related to acreage and mineral acquisitions for 2017.

Coinciding with the recent improvements in oil and natural gas prices in late 2016, we have begun to

experience price increases from our service providers for some of the products and services we use in our drilling,
completion and production operations. If oil and natural gas prices remain at their current levels for a longer
period of time or should they increase further, we would anticipate receiving additional price increases for drilling,
completion and production products and services, although we can provide no assurances as to the eventual
magnitude of these increases.

Like other oil and natural gas producing companies, our properties are subject to natural production declines.

By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to
overcome these production declines by drilling to develop and identify additional reserves, by exploring for new
sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and natural gas liquids
price declines, however, drilling additional oil or natural gas wells may not be economical, and we may ﬁnd it
necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material
reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues,
reserves, cash ﬂows and our availability under our Credit Agreement. See “Risk Factors — Our Exploration,
Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows
from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory
Terms, Which Could Adversely Affect Our Future Growth.”

We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at

a level that is appropriate for long-term operations. Our ability to ﬁnd and develop sufﬁcient quantities of oil and
natural gas reserves at economical costs is critical to our long-term success. Future ﬁnding and development costs
are subject to changes in the costs of acquiring, drilling and completing our prospects.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of ﬁnancial statements in conformity with GAAP requires us to make estimates and assumptions

that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period.
We believe that our estimates and assumptions are reasonable and reliable, and believe that the actual results will
not differ signiﬁcantly from those reported; however, such estimates and assumptions are subject to a number

FORM 10-K PART I I

2016 ANNUAL REPORT

of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from
our estimates. We consider the following to be our most critical accounting policies and estimates involving
signiﬁcant judgment or estimates by our management. See Note 2 to the consolidated ﬁnancial statements in this
Annual Report for further details on our accounting policies at December 31, 2016. Such information is incorporated
herein by reference.

Oil and Natural Gas Properties

We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this
method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas
properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and
accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States.
Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped
properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and
general and administrative expenses directly related to acquisition, exploration and development activities, but do
not include any costs related to production, selling or general corporate administrative activities.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon

production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded
from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for
possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment
includes consideration of the following factors, among others: the assignment of proved reserves, geological
and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment,
the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory
dry holes are included in the amortization base immediately upon the determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or

loss recognized, unless such adjustments would signiﬁcantly alter the relationship between net capitalized costs
and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are
expensed as incurred. Signiﬁcant workovers that increase the properties’ reserves are capitalized.

Ceiling Test

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less

related deferred income taxes or the cost center “ceiling.” The cost center ceiling is deﬁned as the sum of:

(a)

the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves,
reduced by the estimated costs of developing these reserves, plus

(b) unproved and unevaluated property costs not being amortized, plus

(c)

the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs
being amortized, if any, less

(d)

income tax effects related to the properties involved.

Any excess of our net capitalized costs above the cost center ceiling as described above is charged to

operations as a full-cost ceiling impairment. The fair value of our derivative instruments is not included in the ceiling
test computation as we do not designate these instruments as hedge instruments for accounting purposes.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

Because the cost center ceiling calculation is based on the average of historical prices, which may or may not

be representative of future prices, and requires a 10% discount factor, the resulting estimated value may not
be indicative of the fair market value of our properties. Any impairment related to the excess of our net capitalized
costs above the resulting cost center ceiling should not be viewed as an absolute indicator of a reduction in the
ultimate value of the related reserves.

Derivative Financial Instruments

From time to time, we use derivative ﬁnancial instruments to mitigate our exposure to commodity price risk

associated with oil, natural gas and natural gas liquids prices. These instruments typically consist of put and call
options in the form of costless (or zero-cost) collars and swap contracts. Costless collars provide us with downside
price protection through the purchase of a put option which is ﬁnanced through the sale of a call option. Because
the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless”
to us. In the case of a costless collar, the put option and the call option have different ﬁxed price components.
In a swap contract, a ﬂoating price is exchanged for a ﬁxed price over a speciﬁed period, providing downside
price protection.

Prior to settlement, our derivative ﬁnancial instruments are recorded on the balance sheet as either an asset or a

liability measured at fair value. We have elected not to apply hedge accounting for our existing derivative ﬁnancial
instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently in
our consolidated statements of operations. Such changes in fair value are reported under Revenues as “Unrealized
gain (loss) on derivatives.” Changes in the fair value of these open derivative ﬁnancial instruments can have a
signiﬁcant impact on our reported results from period to period but do not impact our cash ﬂows from operations,
liquidity or capital resources. The fair value of our derivative ﬁnancial instruments is determined using industry-
standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of
money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant
economic measures.

Realized gains and realized losses from the settlement of derivative ﬁnancial instruments do have a direct
impact on our cash ﬂow from operations and liquidity. The impact of these settlements is also reported under
Revenues as “Realized gain (loss) on derivatives.”

Revenue Recognition

We follow the sales method of accounting for our oil, natural gas and natural gas liquids revenue, whereby we

recognize revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of
whether the sales are proportionate to our ownership in the property. Under this method, revenue is recognized at
the time the oil, natural gas and natural gas liquids are produced and sold, and we accrue for revenue earned but
not yet received. We recognize midstream services revenues at the time services have been rendered and the price
is ﬁxed and determinable.

FORM 10-K PART I I

2016 ANNUAL REPORT

Stock-Based Compensation

We account for stock-based compensation in accordance with ASC 718. Since 2012, all stock option awards
have been granted under the 2012 Long-Term Incentive Plan or, for awards granted after June 10, 2015, under the
Amended and Restated 2012 Long-Term Incentive Plan, and all of these awards were equity instruments. We did
not grant any stock option awards in 2011. Prior to 2011, all stock option awards were granted under our 2003 Stock
and Incentive Plan, and since November 22, 2010, these awards have been accounted for as liability instruments.
We used the fair value method to measure and recognize the liability associated with our outstanding liability-based
stock options and to measure and recognize the equity associated with our equity-based stock options. Stock
options typically vest over three or four years, and the associated compensation expense is recognized on a straight-
line basis over the vesting period. Restricted stock and restricted stock units typically vest over a period of one to
four years, and compensation expense is recognized on a straight line basis over the vesting period. As our
shares were not publicly traded prior to February 2, 2012, prior to the beginning of 2016, we estimated the future
volatility of our stock using the historical volatility of the common stock of a group of companies we consider
to be a representative peer group. Beginning in 2016, we began using our own historical volatility to estimate the
future volatility of our stock as we had four years of historical stock prices as a publicly traded company.
Management believes that, beginning in 2016, our own average historical volatility rates are the best available
indicator of future volatility.

We have adopted the “simpliﬁed method” as outlined in Staff Accounting Bulletin Topic 14 for estimating the
expected term of awards. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a
term to maturity that is consistent with the expected term of the award.

Assumptions are reviewed each time new equity-based option awards are granted and quarterly for outstanding

liability-based option awards. The assumptions used may be impacted by actual ﬂuctuations in our stock price,
movements in market interest rates and option terms. The use of different assumptions produces a different fair
value for equity-based option awards and outstanding liability-based option awards and can signiﬁcantly impact the
amount of stock compensation expense recognized in our consolidated statement of operations. We use the
Black Scholes Merton model to determine the fair value of service-based option awards and the Monte Carlo
method to determine the fair value of option awards that contain a market condition. The fair value of restricted
stock and restricted stock unit awards is recognized based on the fair value of our stock on the date of the grant.
See Note 8 to the consolidated ﬁnancial statements in this Annual Report for further details on our stock-based
compensation at December 31, 2016. Such information is incorporated herein by reference.

Income Taxes

We account for income taxes using the asset and liability approach for ﬁnancial accounting and reporting. The
amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state
taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses
and tax carryforwards. We evaluate the probability of realizing the future beneﬁts of our deferred tax assets and
provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income
tax beneﬁt in the future does not meet the more likely than not criteria for recognition.

We account for uncertainty in income taxes by recognizing the ﬁnancial statement beneﬁt of a tax position only

after determining that the relevant tax authority would more likely than not sustain the position following an
audit. For tax positions meeting the more likely than not threshold, the amount recognized in the ﬁnancial
statements is the beneﬁt that has a greater than 50% likelihood of being realized upon ultimate settlement with
the relevant tax authority.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue

Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net

revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected
to present only proved reserves in this Annual Report. The applicable rules deﬁne proved reserves as the quantities
of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable
certainty to be economically producible — from a given date forward, from known reservoirs and under existing
economic conditions, operating methods and government regulations — prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of
whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons
must have commenced or the operator must be reasonably certain that it will commence the project within a
reasonable time.

Our engineers and technical staff must make many subjective assumptions based on their professional judgment

in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels
and other technical information about each well. Estimating oil and natural gas reserves is complex and is inexact
because of the numerous uncertainties inherent in the process. The process relies on interpretations of available
geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both
the data and the associated interpretations can vary. The process also requires certain economic assumptions,
including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital
expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our
estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are
ultimately recovered. Any signiﬁcant variance could materially and adversely affect our future reserves estimates,
ﬁnancial condition, results of operations and cash ﬂows. We cannot predict the amounts or timing of future reserves
revisions. If such revisions are signiﬁcant, they could signiﬁcantly affect future amortization of capitalized costs
and result in an impairment of assets that may be material. See “Risk Factors — Our Oil and Natural Gas Reserves
Are Estimated and May Not Reﬂect the Actual Volumes of Oil and Natural Gas We Will Recover, and Signiﬁcant
Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and
Present Value of Our Reserves.”

Recent Accounting Pronouncements

See Note 2 to the consolidated ﬁnancial statements in this Annual Report for a description of recent accounting

pronouncements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty
and customer risk. We address these risks through a program of risk management including the use of derivative
ﬁnancial instruments, but we do not enter into derivative ﬁnancial instruments for trading purposes.

Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and natural gas
liquids ﬂuctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused
by these market ﬂuctuations, we have entered into derivative ﬁnancial instruments in the past and expect to enter
into derivative ﬁnancial instruments in the future to cover a signiﬁcant portion of our anticipated future production.

We typically use costless (or zero-cost) collars and/or swap contracts to manage risks related to changes in oil,

natural gas and natural gas liquids prices. Costless collars provide us with downside price protection through the
purchase of a put option which is ﬁnanced through the sale of a call option. Because the call option proceeds are

FORM 10-K PART I I

2016 ANNUAL REPORT

used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless
collar, the put option and the call option have different ﬁxed price components. In a swap contract, a ﬂoating price is
exchanged for a ﬁxed price over a speciﬁed period, providing downside price protection.

We record all derivative ﬁnancial instruments at fair value. The fair value of our derivative ﬁnancial instruments is

determined using purchase and sale information available for similarly traded securities. At December 31, 2016,
Comerica Bank, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal), and SunTrust Bank (or afﬁliates
thereof) were the counterparties for all of our derivative instruments. We have considered the credit standing of
the counterparties in determining the fair value of our derivative ﬁnancial instruments.

At December 31, 2016, we had entered into various costless collar contracts to mitigate our exposure to

ﬂuctuations in oil and natural gas prices, each with an established price ﬂoor and ceiling. For each calculation period,
the speciﬁed price for determining the realized gain or loss to us pursuant to any oil contract is the arithmetic
average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the ﬁrst nearby
month corresponding to the calculation period’s calendar month, and for any natural gas contract is the settlement
price for the NYMEX Henry Hub natural gas futures contract for the delivery month corresponding to the calculation
period’s calendar month for the settlement date of that contract period.

When the settlement price is below the price ﬂoor established by one or more of these collars, we receive from

our counterparty an amount equal to the difference between the settlement price and the price ﬂoor multiplied
by the contract oil or natural gas volume. When the settlement price is above the price ceiling established by one or
more of these collars, we pay our counterparty an amount equal to the difference between the settlement price
and the price ceiling multiplied by the contract oil or natural gas volume.

See Note 11 to the consolidated ﬁnancial statements in this Annual Report for a summary of our open derivative

ﬁnancial instruments at December 31, 2016. Such information is incorporated herein by reference.

Effect of Recent Derivatives Legislation. On July 21, 2010, President Obama signed into law the Dodd-Frank

Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which is intended to modernize and
protect the integrity of the U.S. ﬁnancial system. The Dodd-Frank Act, among other things, establishes federal
oversight and regulation of certain derivative products including commodity hedges of the type we use. The
Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC to promulgate rules
and regulations implementing the Dodd-Frank Act. Although the CFTC has ﬁnalized certain of these regulations,
others remain to be ﬁnalized or implemented and it is not possible at this time to predict when this will be
accomplished. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there
is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into
and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of
position limits and additional regulatory requirements on our derivative arrangements, which could include new
margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our
counterparties and may increase the cost of our derivative arrangements in the future. See “Risk Factors — The
Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks
Associated with Our Business.”

Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in
an attempt to reduce interest rate expense on existing debt since we borrowed under our Credit Agreement for
the ﬁrst time in December 2010. At December 31, 2016 we had no outstanding borrowings under our Credit
Agreement and $575.0 million in senior notes outstanding at a coupon rate of 6.875% per annum. If we incur
additional indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest
rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the
debt portfolio.

FORM 10-K PART I I

MATADOR RESOURCES COMPANY

Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial
interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases
on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit
risk due to concentration of our oil and natural gas receivables with several signiﬁcant customers. The inability or
failure of our signiﬁcant customers to meet their obligations to us or their insolvency or liquidation may adversely
affect our ﬁnancial condition, results of operations and cash ﬂows. In addition, our oil, natural gas and natural gas
liquids derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties.

While we do not require our customers to post collateral and we do not have a formal process in place to
evaluate and assess the credit standing of our signiﬁcant customers for oil and natural gas receivables and the
counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we
deem appropriate under the circumstances. This evaluation requires us to conduct the due diligence necessary to
determine credit terms and credit limits, which may include (i) reviewing a counterparty’s credit rating, latest
ﬁnancial information and, in the case of a customer with which we have receivables, its historical payment record
and the ﬁnancial ability of its parent company to make payment if the customer cannot and (ii) undertaking the
due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative ﬁnancial
instruments in place at February 22, 2017 were Comerica Bank, The Bank of Nova Scotia, BMO Harris Financing
(Bank of Montreal), and SunTrust Bank (or afﬁliates thereof), which are lenders (or afﬁliates thereof) under our Credit
Agreement, and we are likely to enter into any future derivative instruments with such banks or other lenders (or
afﬁliates thereof) party to the Credit Agreement.

Impact of Inﬂation. Inﬂation in the United States has been relatively low in recent years and did not have a
material impact on our results of operations for the years ended December 31, 2016, 2015 and 2014. Although the
impact of inﬂation has been generally insigniﬁcant in recent years, it is still a factor in the U.S. economy and we
tend to speciﬁcally experience inﬂationary pressure on the cost of oilﬁeld services and equipment with increases in
oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp
and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play. See “Risk
Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and
Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish
and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a
Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.”

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Our ﬁnancial statements appear at the end of this Annual Report. See the index to the ﬁnancial statements in

Item 15.

FORM 10-K PART I I

2016 ANNUAL REPORT

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE.

Not applicable.

ITEM 9A. CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and
operation of the Company’s disclosure controls and procedures (as deﬁned in Rule 13a-15(e) under the Exchange Act)
under the supervision and with the participation of our management, including our Chief Executive Ofﬁcer and our
Chief Financial Ofﬁcer. Based on that evaluation, our Chief Executive Ofﬁcer and our Chief Financial Ofﬁcer concluded
that the Company’s disclosure controls and procedures were effective as of December 31, 2016 to ensure that
(i) information required to be disclosed in the reports it ﬁles and submits under the Exchange Act is recorded,
processed, summarized and reported within the time periods speciﬁed in the SEC’s rules and forms and that
(ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the
Company’s management, including our Chief Executive Ofﬁcer and our Chief Financial Ofﬁcer, as appropriate to
allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2016, there were no changes in our internal controls that have materially

affected or are reasonably likely to have a material effect on our internal control over ﬁnancial reporting.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over ﬁnancial reporting

as deﬁned in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with
the participation of our management, including our Chief Executive Ofﬁcer and our Chief Financial Ofﬁcer, we
assessed the effectiveness of our internal control over ﬁnancial reporting as of the end of the period covered by this
Annual Report based on the framework in 2013 “Internal Control — Integrated Framework” issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief
Executive Ofﬁcer and our Chief Financial Ofﬁcer concluded that our internal control over ﬁnancial reporting was
effective to provide reasonable assurance regarding the reliability of our ﬁnancial reporting and the preparation of
our ﬁnancial statements for external purposes in accordance with U.S. generally accepted accounting principles.

KPMG, our independent registered public accounting ﬁrm, has issued an attestation report on our controls over

ﬁnancial reporting as of December 31, 2016 as included herein.

Important Considerations

The effectiveness of our disclosure controls and procedures and our internal control over ﬁnancial reporting

is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions
about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of
fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls
may become inadequate because of changes in conditions and the risk that the degree of compliance with
policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any
system of disclosure controls and procedures or internal control over ﬁnancial reporting will be successful in
preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels
of management.

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MATADOR RESOURCES COMPANY

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Matador Resources Company:

We have audited Matador Resources Company’s (the “Company”) internal control over ﬁnancial reporting as

of December 31, 2016 based on criteria established in Internal Control - Integrated Framework (2013) issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management
is responsible for maintaining effective internal control over ﬁnancial reporting and for its assessment of the
effectiveness of internal control over ﬁnancial reporting, included in the accompanying Management’s Report on
Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal
control over ﬁnancial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board

(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether effective internal control over ﬁnancial reporting was maintained in all material respects. Our audit included
obtaining an understanding of internal control over ﬁnancial reporting, assessing the risk that a material weakness
exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed
risk. Our audit also included performing such other procedures as we considered necessary in the circumstances.
We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over ﬁnancial reporting is a process designed to provide reasonable assurance
regarding the reliability of ﬁnancial reporting and the preparation of ﬁnancial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over ﬁnancial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reﬂect the transactions and dispositions of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of ﬁnancial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the ﬁnancial statements.

Because of its inherent limitations, internal control over ﬁnancial reporting may not prevent or detect

misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over ﬁnancial

reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013)
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the consolidated balance sheets of the Company and subsidiaries as of December 31, 2016, 2015
and 2014, and the related consolidated statements of operations, changes in shareholders’ equity, and cash
ﬂows for each of the years in the three-year period ended December 31, 2016, and our report dated March 1, 2017
expressed an unqualiﬁed opinion on those consolidated ﬁnancial statements.

/s/ KPMG LLP

Dallas, Texas
March 1, 2017

FORM 10-K PART I I

ITEM 9B. OTHER INFORMATION.

Not applicable.

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101

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MATADOR RESOURCES COMPANY

Part III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

statement to be ﬁled with the SEC pursuant to Regulation 14A promulgated under the Exchange Act, not later than
120 days after the end of the ﬁscal year covered by this Annual Report.

ITEM 11. EXECUTIVE COMPENSATION.

The information required in response to this Item 11 is incorporated herein by reference to our deﬁnitive proxy
statement to be ﬁled with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than
120 days after the end of the ﬁscal year covered by this Annual Report.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND

RELATED STOCKHOLDER MATTERS.

Certain information regarding securities authorized for issuance under our equity compensation plans is included

under the caption “Equity Compensation Plan Information” in Part II, Item 5, above, of this Annual Report and is
incorporated by reference herein. Other information required in response to this Item 12 is incorporated herein by
reference to our deﬁnitive proxy statement to be ﬁled with the SEC pursuant to Regulation 14A promulgated under
the Exchange Act not later than 120 days after the end of the ﬁscal year covered by this Annual Report.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR

INDEPENDENCE.

The information required in response to this Item 13 is incorporated herein by reference to our deﬁnitive proxy
statement to be ﬁled with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than
120 days after the end of the ﬁscal year covered by this Annual Report.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

The information required in response to this Item 14 is incorporated herein by reference to our deﬁnitive proxy
statement to be ﬁled with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than
120 days after the end of the ﬁscal year covered by this Annual Report.

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103

Part IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

The following documents are ﬁled as part of this Annual Report:

1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm,

Consolidated Balance Sheets as of December 31, 2016 and 2015, Consolidated Statements of Operations
for the Years Ended December 31, 2016, 2015 and 2014, Consolidated Statements of Changes in
Shareholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014 and Consolidated Statements
of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014.

2. Exhibits: The exhibits required to be ﬁled by this Item 15 are set forth in the Exhibit Index accompanying

this Annual Report.

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MATADOR RESOURCES COMPANY

Exhibit Index

Exhibit
Number

Description

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

2.10

2.11

2.12

3.1

3.2

3.3

3.4

3.5

4.1

Agreement and Plan of Merger, by and among Matador Resources Company (now known as MRC Energy Company),
Matador Holdco, Inc. (now known as Matador Resources Company) and Matador Merger Co., dated August 8, 2011
(incorporated by reference to Exhibit 2.1 to our Registration Statement on Form S-1 ﬁled on August 12, 2011).

Agreement and Plan of Merger, dated as of January 19, 2015, by and among HEYCO Energy Group, Inc., Harvey E.
Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to
Exhibit 2.1 to the Current Report on Form 8-K ﬁled on January 20, 2015).*

Amendment No. 1 to Agreement and Plan of Merger, dated as of January 26, 2015, by and among HEYCO Energy
Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated
by reference to Exhibit 2.3 to our Annual Report on Form 10-K for the year ended December 31, 2014).

Amendment No. 2 to Agreement and Plan of Merger, dated as of February 2, 2015, by and among HEYCO Energy
Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated
by reference to Exhibit 2.4 to our Annual Report on Form 10-K for the year ended December 31, 2014).

Amendment No. 3 to Agreement and Plan of Merger, dated as of February 6, 2015, by and among HEYCO Energy
Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated
by reference to Exhibit 2.5 to our Annual Report on Form 10-K for the year ended December 31, 2014).*

Amendment No. 4 to Agreement and Plan of Merger, dated as of February 27, 2015, by and among HEYCO Energy
Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated
by reference to Exhibit 2.2 to the Current Report on Form 8-K ﬁled on March 2, 2015).*

Amendment No. 5 to Agreement and Plan of Merger, dated as of April 15, 2015, by and among HEYCO Energy Group,
Inc., Matador Resources Company and MRC Delaware Resources, LLC (incorporated by reference to Exhibit 2.1 to the
Current Report on Form 8-K ﬁled on April 15, 2015).

Amendment No. 6 to Agreement and Plan of Merger, dated as of July 20, 2015, by and among HEYCO Energy Group,
Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by
reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015).

Amendment No. 7 to Agreement and Plan of Merger, dated as of August 24, 2015, by and among HEYCO Energy
Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated
by reference to Exhibit 2.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015).

Amendment No. 8 to Agreement and Plan of Merger, dated as of September 18, 2015, by and among HEYCO Energy
Group, Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated
by reference to Exhibit 2.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015).

Amendment No. 9 to Agreement and Plan of Merger, dated as of March 1, 2016, by and among HEYCO Energy Group,
Inc., Harvey E. Yates Company, Matador Resources Company and MRC Delaware Resources, LLC (incorporated by
reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2016).

Subscription and Contribution Agreement, dated as of February 17, 2017, by and among Longwood Midstream
Holdings, LLC, FP MMP Holdings LLC and San Mateo Midstream, LLC (incorporated by reference to Exhibit 2.1 to the
Current Report on Form 8-K ﬁled on February 24, 2017).*

Certiﬁcate of Merger between Matador Resources Company (now known as MRC Energy Company) and Matador
Merger Co. (incorporated by reference to Exhibit 3.4 to our Registration Statement on Form S-1 ﬁled on August 12, 2011).

Amended and Restated Certiﬁcate of Formation of Matador Resources Company (incorporated by reference to Exhibit
3.1 to the Current Report on Form 8-K ﬁled on February 13, 2012).

Certiﬁcate of Amendment to the Amended and Restated Certiﬁcate of Formation of Matador Resources Company
(incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2015).

Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1
to the Current Report on Form 8-K ﬁled on December 23, 2016).

Statement of Resolutions for Series A Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 to the
Current Report on Form 8-K ﬁled on March 2, 2015).

Form of Common Stock Certiﬁcate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to our Registration
Statement on Form S-1 ﬁled on January 19, 2012).

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2016 ANNUAL REPORT

105

Exhibit
Number

Description

4.2

4.3

4.4

4.5

4.6

4.7

4.8

4.9

10.1†

10.2†

10.3†

10.4†

10.5†

10.6†

10.7†

10.8†

10.9†

Registration Rights Agreement, dated February 27, 2015, between Matador Resources Company and HEYCO Energy
Group, Inc. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K ﬁled on March 2, 2015).

Voting Agreement, dated February 27, 2015, between Matador Resources Company and HEYCO Energy Group, Inc.
(incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K ﬁled on March 2, 2015).

Indenture, dated as of April 14, 2015, by and among Matador Resources Company, the subsidiary guarantors party
thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current
Report on Form 8-K ﬁled on April 14, 2015).

First Supplemental Indenture, dated as of October 1, 2015, by and among Matador Resources Company, DLK Wolf
Midstream, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by
reference to Exhibit 4.1 to the Current Report on Form 8-K ﬁled on October 5, 2015).

Second Supplemental Indenture, dated as of November 4, 2015, by and among Matador Resources Company, MRC
Permian LKE Company, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee
(incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2015).

Third Supplemental Indenture, dated as of June 8, 2016, by and among Matador Resources Company, Black River Water
Management Company, LLC, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee
(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K ﬁled on June 14, 2016).

Registration Rights Agreement, dated as of December 9, 2016, by and among Matador Resources Company, the
subsidiary guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the
several initial purchasers named therein (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K ﬁled
on December 9, 2016).

Fourth Supplemental Indenture, dated as of February 17, 2017, by and among Matador Resources Company, Black River
Water Management Company, LLC, DLK Black River Midstream, LLC, Longwood Midstream Holdings, LLC, the
Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit
4.1 to the Current Report on Form 8-K ﬁled on February 24, 2017).

Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to
Exhibit 10.3 to Amendment No. 1 to our Registration Statement on Form S-1 ﬁled on November 14, 2011).

Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to
Exhibit 10.4 to Amendment No. 1 to our Registration Statement on Form S-1 ﬁled on November 14, 2011).

Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to
Exhibit 10.5 to Amendment No. 1 to our Registration Statement on Form S-1 ﬁled on November 14, 2011).

Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference
to Exhibit 10.6 to Amendment No. 1 to our Registration Statement on Form S-1 ﬁled on November 14, 2011).

First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran
(incorporated by reference to Exhibit 10.8 to Amendment No. 1 to our Registration Statement on Form S-1 ﬁled on
November 14, 2011).

First Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster
(incorporated by reference to Exhibit 10.9 to Amendment No. 1 to our Registration Statement on Form S-1 ﬁled on
November 14, 2011).

First Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford
(incorporated by reference to Exhibit 10.10 to Amendment No. 1 to our Registration Statement on Form S-1 ﬁled on
November 14, 2011).

First Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson
(incorporated by reference to Exhibit 10.11 to Amendment No. 1 to our Registration Statement on Form S-1 ﬁled on
November 14, 2011).

Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran
(incorporated by reference to Exhibit 10.12 to Amendment No. 2 to our Registration Statement on Form S-1 ﬁled on
December 30, 2011).

FORM 10-K PART I V

106

MATADOR RESOURCES COMPANY

Exhibit
Number

10.10†

10.11†

10.12†

10.13†

10.14†

10.15†

10.16†

10.17†

10.18†

10.19†

10.20†

10.21†

10.22†

10.23†

10.24

10.25

Description

Second Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster
(incorporated by reference to Exhibit 10.13 to Amendment No. 2 to our Registration Statement on Form S-1 ﬁled on
December 30, 2011).

Second Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford
(incorporated by reference to Exhibit 10.14 to Amendment No. 2 to our Registration Statement on Form S-1 ﬁled on
December 30, 2011).

Second Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson
(incorporated by reference to Exhibit 10.15 to Amendment No. 2 to our Registration Statement on Form S-1 ﬁled on
December 30, 2011).

Matador Resources Company Amended and Restated Annual Incentive Plan for Management and Key Employees
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on June 14, 2016).

Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated October
23, 2003 (incorporated by reference to Exhibit 10.15 to Amendment No. 1 to our Registration Statement on Form S-1
ﬁled on November 14, 2011).

First Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive
Plan, dated January 29, 2004 (incorporated by reference to Exhibit 10.16 to Amendment No. 1 to our Registration
Statement on Form S-1 ﬁled on November 14, 2011).

Second Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive
Plan, dated February 3, 2005 (incorporated by reference to Exhibit 10.17 to Amendment No. 1 to our Registration
Statement on Form S-1 ﬁled on November 14, 2011).

Third Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive
Plan, dated February 1, 2006 (incorporated by reference to Exhibit 10.18 to Amendment No. 1 to our Registration
Statement on Form S-1 ﬁled on November 14, 2011).

Fourth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive
Plan, dated May 1, 2006 (incorporated by reference to Exhibit 10.19 to Amendment No. 1 to our Registration Statement
on Form S-1 ﬁled on November 14, 2011).

Fifth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive
Plan, dated February 13, 2008 (incorporated by reference to Exhibit 10.20 to Amendment No. 1 to our Registration
Statement on Form S-1 ﬁled on November 14, 2011).

Sixth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive
Plan, dated August 5, 2008 (incorporated by reference to Exhibit 10.21 to Amendment No. 1 to our Registration
Statement on Form S-1 ﬁled on November 14, 2011).

Seventh Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and
Incentive Plan, dated December 12, 2011 (incorporated by reference to Exhibit 10.26 to Amendment No. 2 to our
Registration Statement on Form S-1 ﬁled on December 30, 2011).

Eighth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive
Plan, dated March 8, 2013 (incorporated by reference to Exhibit 10.27 to the Annual Report on Form 10-K for the year
ended December 31, 2012).

Form of Indemniﬁcation Agreement between Matador Resources Company and each of the directors and executive
ofﬁcers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to our Registration Statement on
Form S-1 ﬁled on November 14, 2011).

Purchase, Sale and Participation Agreement, by and between Matador Resources Company (now known as
MRC Energy Company) and Orca ICI Development, JV, dated at May 16, 2011 (incorporated by reference to
Exhibit 10.25 to Amendment No. 1 to our Registration Statement on Form S-1 ﬁled on November 14, 2011).

First Amendment to Purchase Sale and Participation Agreement, dated as of June 12, 2013, by and between
MRC Energy Company and Orca/ICI Development (incorporated by reference to Exhibit 10.3 to the Quarterly Report
on Form 10-Q for the quarter ended June 30, 2013).

FORM 10-K PART I V

2016 ANNUAL REPORT

107

Exhibit
Number

10.26†

10.27†

10.28†

10.29†

10.30†

10.31†

10.32†

10.33†

10.34†

10.35†

10.36†

10.37

10.38

10.39

10.40

Description

Form of Non-Qualiﬁed Stock Option Agreement granted pursuant to the Matador Resources Company (now known as
MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.36 to the Annual Report
on Form 10-K for the year ended December 31, 2011).

Form of Incentive Stock Option Agreement granted pursuant to the Matador Resources Company (now known as
MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.37 to the Annual Report
on Form 10-K for the year ended December 31, 2011).

Form of Nonqualiﬁed Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.38 to the Annual Report on Form 10-K for the year ended
December 31, 2011).

Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term
Incentive Plan (incorporated by reference to Exhibit 10.39 to the Annual Report on Form 10-K for the year ended
December 31, 2011).

Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan
(incorporated by reference to Exhibit 10.40 to the Annual Report on Form 10-K for the year ended December 31, 2011).

Form of Nonqualiﬁed Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive
Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report
on Form 10-Q for the quarter ended March 31, 2012).

Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive
Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report
on Form 10-Q for the quarter ended March 31, 2012).

Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources
Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference
to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012).

Form of Nonqualiﬁed Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive
Plan for employees with employment agreements (incorporated by reference to Exhibit 10.8 to the Quarterly Report on
Form 10-Q for the quarter ended March 31, 2012).

Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive
Plan for employees with employment agreements (incorporated by reference to Exhibit 10.9 to the Quarterly Report on
Form 10-Q for the quarter ended March 31, 2012).

Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources
Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to
Exhibit 10.10 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012).

Third Amended and Restated Credit Agreement, dated as of September 28, 2012, by and among MRC Energy
Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of
Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on
October 4, 2012).

Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood
Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of
September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended
December 31, 2012).

Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC
Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood
Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative
Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K
for the year ended December 31, 2012).

First Amendment to Third Amended and Restated Credit Agreement dated as of March 11, 2013, by and among MRC
Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2012).

FORM 10-K PART I V

108

MATADOR RESOURCES COMPANY

Exhibit
Number

10.41

10.42

10.43

10.44

10.45

10.46

10.47

10.48

10.49†

10.50†

10.51†

10.52†

10.53†

10.54†

10.55†

10.56†

Description

Second Amendment to Third Amended and Restated Credit Agreement dated as of June 4, 2013, by and among
MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled June 6, 2013).

Third Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2013, by and among MRC
Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013).

Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of March 12, 2014, by and among
MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2013).

Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of September 5, 2014, by and among
MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on September 8, 2014).

Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of April 14, 2015, by and among MRC
Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K ﬁled on April 14, 2015).

Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of October 16, 2015, by and among
MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on October 21, 2015).

Eighth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, by and among
MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on November 2, 2016).

Limited Consent and Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of December 9,
2016, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada,
as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K ﬁled on
December 9, 2016).

Form of Employment Agreement between Matador Resources Company and Craig N. Adams (incorporated by
reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2013).

Letter Agreement between Matador Resources Company, David F. Nicklin and David F. Nicklin International
Consulting, Inc., dated February 26, 2015 (incorporated by reference to Exhibit 10.51 to our Annual Report on
Form 10-K for the year ended December 31, 2014).

Form of Employment Agreement between Matador Resources Company and Van H. Singleton, II, effective
February 5, 2015 (incorporated by reference to Exhibit 10.52 to our Annual Report on Form 10-K for the year ended
December 31, 2014).

Form of Nonqualiﬁed Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive
Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54 to our Annual Report
on Form 10-K for the year ended December 31, 2014).

Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive
Plan for employees without employment agreements (incorporated by reference to Exhibit 10.55 to our Annual Report
on Form 10-K for the year ended December 31, 2014).

Form of Nonqualiﬁed Stock Option Agreement relating to the Matador Resources Company Amended and Restated
2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit
10.53 to our Annual Report on Form 10-K for the year ended December 31, 2015).

Form of Restricted Stock Award Agreement relating to the Matador Resources Company Amended and Restated 2012
Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.54
to our Annual Report on Form 10-K for the year ended December 31, 2015).

Amended and Restated Independent Contractor Agreement by and among Matador Resources Company, David
F. Nicklin and David F. Nicklin International Consulting, Inc., effective as of April 1, 2015 (incorporated by reference to
Exhibit 10.1 to the Current Report on Form 8-K ﬁled on June 11, 2015).

FORM 10-K PART I V

2016 ANNUAL REPORT

109

Exhibit
Number

10.57

10.58†

10.59†

10.60†

10.61

10.62†

10.63†

10.64†

21.1

23.1

23.2

31.1

31.2

32.1

32.2

99.1

101

Description

Purchase Agreement, dated as of April 9, 2015, by and among Matador Resources Company, the subsidiary guarantors
party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers
named therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on April 14, 2015).

Amended and Restated 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current Report
on Form 8-K ﬁled on June 11, 2015).

Separation Agreement and Release, dated as of August 31, 2015, by and between Matador Resources Company and
Ryan C. London (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q/A for the quarter
ended September 30, 2015).

Matador Resources Company Nonqualiﬁed Deferred Compensation Plan for Non-Employee Directors (incorporated by
reference to Exhibit 10.59 to our Annual Report on Form 10-K for the year ended December 31, 2015).

Purchase Agreement, dated as of December 6, 2016, by and among Matador Resources Company, the subsidiary
guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial
purchasers named therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K ﬁled on
December 9, 2016).

Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term
Incentive Plan (ﬁled herewith).

Form of Restricted Stock Unit Award Agreement for deferred delivery relating to the Matador Resources Company
2012 Long-Term Incentive Plan (ﬁled herewith).

Form of Letter Agreement between Matador Resources Company and certain directors modifying Restricted Stock
Unit Award Agreements (ﬁled herewith).

List of Subsidiaries of Matador Resources Company (ﬁled herewith).

Consent of KPMG LLP (ﬁled herewith).

Consent of Netherland, Sewell & Associates, Inc. (ﬁled herewith).

Certiﬁcation of Principal Executive Ofﬁcer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (ﬁled herewith).

Certiﬁcation of Principal Financial Ofﬁcer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (ﬁled herewith).

Certiﬁcation of Principal Executive Ofﬁcer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 (furnished herewith).

Certiﬁcation of Principal Financial Ofﬁcer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 (furnished herewith).

Audit report of Netherland, Sewell & Associates, Inc. (ﬁled herewith).

The following ﬁnancial information from Matador Resources Company’s Annual Report on Form 10-K for the year
ended December 31, 2016, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Balance
Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Changes in Shareholders’
Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements
(submitted electronically herewith).

†

Indicates a management contract or compensatory plan or arrangement.

* Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any omitted exhibit or schedule to the

SEC upon request.

FORM 10-K PART I V

110

MATADOR RESOURCES COMPANY

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has

duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

March 1, 2017

MATADOR RESOURCES COMPANY

By:

/s/ JOSEPH WM. FORAN
Joseph Wm. Foran
Chairman and Chief Executive Ofﬁcer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below
by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature

Title

/s/ JOSEPH WM. FORAN
Joseph Wm. Foran

Chairman and Chief Executive Ofﬁcer
(Principal Executive Ofﬁcer)

Date

March 1, 2017

/s/ DAVID E. LANCASTER
David E. Lancaster

Executive Vice President and Chief Financial Ofﬁcer
(Principal Financial Ofﬁcer)

March 1, 2017

/s/ ROBERT T. MACALIK
Robert T. Macalik

Vice President and Chief Accounting Ofﬁcer
(Principal Accounting Ofﬁcer)

March 1, 2017

/s/ REYNALD A. BARIBAULT
Reynald A. Baribault

/s/ R. GAINES BATY
R. Gaines Baty

/s/ CRAIG T. BURKERT
Craig T. Burkert

/s/ WILLIAM M. BYERLEY
William M. Byerley

/s/ JOE A. DAVIS
Joe A. Davis

/s/ JULIA P. FORRESTER
Julia P. Forrester

/s/ DAVID M. LANEY
David M. Laney

/s/ GREGORY E. MITCHELL
Gregory E. Mitchell

/s/ STEVEN W. OHNIMUS
Steven W. Ohnimus

/s/ KENNETH L. STEWART
Kenneth L. Stewart

/s/ GEORGE M. YATES
George M. Yates

FORM 10-K Signatures

Director

March 1, 2017

2016 ANNUAL REPORT

111

Glossary of Oil and Natural Gas Terms

The following is a description of the meanings of some of the oil and natural gas industry terms used in this

Annual Report.

Batch drilling. The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the
surface holes for each well are drilled ﬁrst and then the production holes, including the horizontal laterals for each well,
are drilled.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil or

other liquid hydrocarbons.

Bcf. One billion cubic feet.

BOE. Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids

to six Mcf of natural gas.

BOE/d. BOE per day.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one

degree Fahrenheit.

Completion. The operations required to establish production of oil or natural gas from a wellbore, usually involving

perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the
reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reservoir.

Conventional reservoirs or resources. Natural gas or oil that is produced by a well drilled into a geologic formation

in which the reservoir and ﬂuid characteristics permit the natural gas or oil to readily ﬂow to the wellbore.

Coring. The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter,

taken as a sample of an underground formation. It is common practice to take cores from wells in the process
of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the
formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its
characteristics (porosity, permeability, etc.) are determined.

Developed acreage. The number of acres that are allocated or assignable to productive wells.

Development well. A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon

known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufﬁcient quantities such that proceeds from

the sale of such production exceed production-related expenses and taxes.

Exploratory well. A well drilled to ﬁnd and produce oil or natural gas reserves not classiﬁed as proved, to ﬁnd
a new reservoir in a ﬁeld previously found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.

Farmin or farmout. An agreement under which the owner of a working interest in an oil or natural gas lease
assigns the working interest or a portion of the working interest to another party who desires to drill on the leased
acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage.
The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a
“farmin” while the interest transferred by the assignor is a “farmout.”

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same

individual geological structural feature and/or stratigraphic condition.

Glossary of Oil and Natural Gas Terms FORM 10-K

112

MATADOR RESOURCES COMPANY

Gross acres or gross wells. The total acres or wells in which a working interest is owned.

Held by production. An oil and natural gas property under lease in which the lease continues to be in force after

the primary term of the lease in accordance with its terms as a result of production from the property.

Horizontal drilling or well. A drilling operation in which a portion of the well is drilled horizontally within a

productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to
produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace
multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption.

Hydraulic fracturing. The technique of improving a well’s production or injection rates by pumping a mixture of
ﬂuids into the formation and rupturing the rock, creating an artiﬁcial channel. As part of this technique, sand or other
material may also be injected into the formation to prop the channel open, so that ﬂuids or gases may more easily
ﬂow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to
as fracture stimulation.

Liquids. Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane

and natural gasoline resulting from the further processing of liqueﬁable hydrocarbons separated from raw natural
gas by a natural gas processing facility.

MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.

MBOE. One thousand BOE.

Mcf. One thousand cubic feet of natural gas.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

NGL. Natural gas liquids.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or wells.

Net revenue interest. The interest that deﬁnes the percentage of revenue that an owner of a well receives from

the sale of oil, natural gas and/or natural gas liquids that are produced from the well.

NYMEX. New York Mercantile Exchange.

Overriding royalty interest. A fractional interest in the gross production of oil and natural gas under a lease, in

addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development,
operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the
lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved
royalty interest.

Pad. The surface constructed to accommodate the drilling, completion and production operations of an oil or

natural gas well.

Pad drilling. The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each well

on the pad is drilled to total depth before the next well is initiated.

Permeability. A reference to the ability of oil and/or natural gas to ﬂow through a reservoir.

Petrophysical analysis. The interpretation of well log measurements, obtained from a string of electronic tools
inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface,
then combining these measurements with other relevant geological and geophysical information to describe the
reservoir rock properties.

FORM 10-K Glossary of Oil and Natural Gas Terms

2016 ANNUAL REPORT

113

Play. A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and
temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type.

Possible reserves. Additional reserves that are less certain to be recognized than probable reserves.

Probable reserves. Additional reserves that are less certain to be recognized than proved reserves but which, in

sum with proved reserves, are as likely as not to be recovered.

Producing well, or productive well. A well that is found to be capable of producing hydrocarbons in sufﬁcient
quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes.

Properties. Natural gas and oil wells, production and related equipment and facilities and oil, natural gas, or other

mineral fee, leasehold and related interests.

Prospect. A speciﬁc geographic area which, based on supporting geological, geophysical or other data and

preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the
discovery of commercial hydrocarbons.

Proved developed non-producing. Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the
production of which has been postponed pending installation of surface equipment or gathering facilities, or pending
the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classiﬁed
as proved developed but non-producing reserves.

Proved developed reserves. Proved reserves that can be expected to be recovered through existing wells and

facilities and by existing operating methods.

Proved reserves. Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis

of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled

acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. Completing in the same wellbore to reach a new reservoir after production from the original

reservoir has been abandoned.

Repeatability. The potential ability to drill multiple wells within a prospect or trend.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible
oil and/or natural gas that is conﬁned by impermeable rock or water barriers and is individual and separate from
other reservoirs.

Royalty interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive

a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not
require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties
may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease
is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a
transfer to a subsequent owner.

2-D seismic. The method by which a cross-section of the earth’s subsurface is created through the interpretation

of reﬂecting seismic data collected along a single source proﬁle.

3-D seismic. The method by which a three-dimensional image of the earth’s subsurface is created through the
interpretation of reﬂection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed
understanding of the subsurface than do 2-D seismic surveys and contribute signiﬁcantly to ﬁeld appraisal,
exploitation and production.

Glossary of Oil and Natural Gas Terms FORM 10-K

114

MATADOR RESOURCES COMPANY

Spud. The act of beginning to drill an oil or natural gas well.

Throughput. The volume of product transported or passing through a pipeline, plant or other facility.

Trend. A region of oil and/or natural gas production, the geographic limits of which have not been fully deﬁned,
having geological characteristics that have been ascertained through supporting geological, geophysical or other
data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations.

Unconventional resource play. A set of known or postulated oil and or natural gas resources or reserves
warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations
and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural
gas resources.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains
proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to
productive wells.

Unproved and unevaluated properties. Properties where no drilling or other actions have been undertaken that

permit such properties to be classiﬁed as proved and to which no proved reserves have been assigned.

Vertical well. A hole drilled vertically into the earth from which oil, natural gas or water ﬂows or is pumped.

Visualization. An exploration technique in which the size and shape of subsurface features are mapped and

analyzed based upon information derived from well logs, seismic data and other well information.

Volumetric reserve analysis. A technique used to estimate the amount of recoverable oil and natural gas. It

involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation,
formation volume factor and recovery factor.

Walking rig. A drilling rig that is capable of moving from one drilling location to another a short distance away

using a series of hydraulic “feet” built into the substructure of the rig.

Wellbore. The hole made by a well.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating

activities on the property and receive a share of production.

FORM 10-K Glossary of Oil and Natural Gas Terms

2016 ANNUAL REPORT

F-1

Consolidated Financial Statements

MATADOR RESOURCES COMPANY AND SUBSIDIARIES
December 31, 2016, 2015 and 2014

Contents

Page

Reports of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

F-2

Consolidated Financial Statements

Consolidated Balance Sheets as of December 31, 2016 and 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014 . . . . . . . . . . .

Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2016, 2015

and 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014 . . . . . . . . . . .

Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

F-3

F-4

F-5

F-6

F-7

Unaudited Supplementary Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-40

Consolidated Financial Statements FORM 10-K

F-2

MATADOR RESOURCES COMPANY

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Matador Resources Company:

We have audited the accompanying consolidated balance sheets of Matador Resources Company and subsidiaries

(collectively the “Company”) as of December 31, 2016 and 2015 and the related consolidated statements of
operations, changes in shareholders’ equity and cash ﬂows for each of the years in the three-year period ended
December 31, 2016. These consolidated ﬁnancial statements are the responsibility of the Company’s management.
Our responsibility is to express an opinion on these consolidated ﬁnancial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board

(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the ﬁnancial statements are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the ﬁnancial statements. An audit also includes assessing
the accounting principles used and signiﬁcant estimates made by management, as well as evaluating the overall
ﬁnancial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated ﬁnancial statements referred to above present fairly, in all material respects, the

ﬁnancial position of Matador Resources Company and subsidiaries as of December 31, 2016 and 2015, and the
results of their operations and their cash ﬂows for each of the years in the three-year period ended December 31, 2016,
in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the Company’s internal control over ﬁnancial reporting as of December 31, 2016, based on criteria
established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO), and our report dated March 1, 2017 expressed an unqualiﬁed
opinion on the effectiveness of the Company’s internal control over ﬁnancial reporting.

Dallas, Texas
March 1, 2017

/s/ KPMG LLP

FORM 10-K Consolidated Financial Statements

Consolidated Balance Sheets

Matador Resources Company and Subsidiaries

(In thousands, except par value and share data)

ASSETS
Current assets

Cash
Restricted cash
Accounts receivable

Oil and natural gas revenues

Joint interest billings
Other
Derivative instruments
Lease and well equipment inventory
Prepaid expenses and other assets

Total current assets
Property and equipment, at cost

Oil and natural gas properties, full-cost method
Evaluated

Unproved and unevaluated
Other property and equipment
Less accumulated depletion, depreciation and amortization

Net property and equipment

Other assets

Total assets

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities

Accounts payable
Accrued liabilities
Royalties payable
Amounts due to afﬁliates
Derivative instruments
Advances from joint interest owners
Deferred gain on plant sale
Amounts due to joint ventures
Income taxes payable
Other current liabilities

Total current liabilities

Long-term liabilities

Senior unsecured notes payable
Asset retirement obligations
Derivative instruments
Amounts due to joint ventures
Deferred gain on plant sale
Other long-term liabilities

Total long-term liabilities

Commitments and contingencies (Note 13)
Shareholders’ equity

Common stock — $0.01 par value, 120,000,000 shares authorized; 99,518,764 and

85,567,021 shares issued; and 99,511,931 and 85,564,435 shares outstanding, respectively

Additional paid-in capital
Accumulated deﬁcit

Total Matador Resources Company shareholders’ equity

Non-controlling interest in subsidiaries

Total shareholders’ equity

Total liabilities and shareholders’ equity

The accompanying notes are an integral part of these ﬁnancial statements.

2016 ANNUAL REPORT

F-3

December 31,

2016

2015

$ 212,884
1,258

16,732
44,357

34,154
19,347
5,167
—
3,045
3,327
279,182

16,616
16,999
10,794
16,284
2,022
3,203
127,007

2,408,305
479,736
160,795
(1,864,311)
1,184,525
958
$ 1,464,665

2,122,174
387,504
86,387
(1,583,659)
1,012,406
1,448
$ 1,140,861

4,674
101,460
23,988
8,651
24,203
1,700
—
4,251
—
578
169,505

573,924
19,725
751
1,771
—
7,544
603,715

10,966
92,369
16,493
5,670
—
700
4,830
2,793
2,848
161
136,830

391,254
15,166
—
3,956
102,506
2,190
515,072

995
1,325,481
(636,351)
690,125
1,320
691,445
$ 1,464,665

856
1,026,077
(538,930)
488,003
956
488,959
$ 1,140,861

Consolidated Financial Statements FORM 10-K

F-4

MATADOR RESOURCES COMPANY

Consolidated Statements of Operations

Matador Resources Company and Subsidiaries

(In thousands, except per share data)

Revenues

Oil and natural gas revenues
Third-party midstream services revenues
Realized gain on derivatives
Unrealized (loss) gain on derivatives

Total revenues

Expenses

Production taxes, transportation and processing
Lease operating
Plant and other midstream services operating
Depletion, depreciation and amortization
Accretion of asset retirement obligations
Full-cost ceiling impairment
General and administrative

Total expenses
Operating (loss) income
Other income (expense)

Net gain on asset sales and inventory impairment
Interest expense
Other (expense) income
Total other income (expense)

(Loss) income before income taxes

Income tax provision (beneﬁt)

Current
Deferred
Total income tax (beneﬁt) provision

Net (loss) income

Net (income) loss attributable to non-controlling interest in subsidiaries
Net (loss) income attributable to Matador Resources Company shareholders

Earnings (loss) per common share

Basic

Diluted

Weighted average common shares outstanding

Basic

Diluted

The accompanying notes are an integral part of these ﬁnancial statements.

For the Years Ended December 31,

2016

2015

2014

$ 291,156
5,218
9,286
(41,238)
264,422

$ 278,340
1,864
77,094
(39,265)
318,033

$367,712
1,213
5,022
58,302
432,249

43,046
56,202
5,389
122,048
1,182
158,633
55,089
441,589
(177,167)

107,277
(28,199)
(4)
79,074
(98,093)

35,650
54,704
3,489
178,847
734
801,166
50,105
1,124,695
(806,662)

908
(21,754)
616
(20,230)
(826,892)

33,172
49,945
1,408
134,737
504
—
32,152
251,918
180,331

—
(5,334)
132
(5,202)
175,129

(1,036)

—

(1,036)
(97,057)
(364)
$ (97,421)

2,959
(150,327)
(147,368)
(679,524)
(261)

133
64,242
64,375
110,754
17
$ (679,785) $110,771

(1.07)

(8.34) $

1.58

1.56

91,273

81,537

70,229

91,273

81,537

70,906

FORM 10-K Consolidated Financial Statements

Consolidated Statements of Changes in Shareholders’ Equity

Matador Resources Company and Subsidiaries

For the Years Ended December 31, 2016, 2015 and 2014

Total
shareholders’

equity

Non-

2016 ANNUAL REPORT

F-5

Common Stock

Preferred Stock

Shares Amount

Additional
paid-in
capital

Retained
earnings
(deﬁcit)

Treasury Stock

Amount

attributable controlling
to Matador
Resources
Company

interest
in
subsidiaries

Total
shareholders’
equity

(In thousands)

Balance at January 1, 2014
Issuance of common stock
Cost to issue equity
Issuance of common stock
pursuant to directors’ and
advisors’ compensation plan
Stock options expense related to
equity-based awards
Stock options exercised, net of options
forfeited in net share settlements
Liability-based stock option awards
settled
Restricted stock issued
Restricted stock forfeited
Restricted stock and restricted stock
units expense
Cancellation of treasury stock
Capital contributed to less-than-
wholly-owned subsidiaries
Current period net income (loss)

Balance at December 31, 2014
Issuance of common stock
Issuance of preferred stock
Cost to issue equity
Conversion of preferred stock to
common stock
Stock-based compensation expense
related to equity-based awards
Stock options exercised, net of options
forfeited in net share settlements
Liability-based stock option awards
settled
Restricted stock issued
Restricted stock forfeited
Vesting of restricted stock units
Cancellation of treasury stock
Capital contributed from less-than-
wholly-owned subsidiaries
Current period net (loss) income

Balance at December 31, 2015
Issuance of common stock
pursuant to public offerings
Issuance of common stock
pursuant to employee stock
compensation plan
Issuance of common stock
pursuant to directors’ and
advisors’ compensation plan
Cost to issue equity
Stock-based compensation expense
elated to equity-based awards
Stock options exercised, net of options
forfeited in net share settlements
Liability-based stock option awards
settled
Restricted stock forfeited
Cancellation of treasury stock
Current period net (loss) income

66,959
7,500
—

$ 670
75
—

— $ — $ 548,935 $ 30,084
—
—
—
—

181,800
(590)

—
—

1,306 $ (10,765) $ 568,924 $ — $ 568,924
181,875
181,875
—
(590)
(590)
—

—
—

3,023
(10,752)

—
—

—
(1,335)

—
10,765

3,023
—

—
—

3,023
—

—

2,279

—

—
212
—

—
2
—

—
—
—

—
(1,335)

—
—
(13) —

—
—

73,374
10,329
—
—

734
104
—
—

—
—
150
—

—
—
—

—
—

—
—
1
—

84
(2)
(17)

—

—
—
—

—
—
60

—
—

—
110,771

—
—

724,819
260,148
32,489
(1,151)

140,855
—
—
—

31
—
—
—

1,500

(150)

(1)

(14)

—

9,333

—

25
429
—
52
(167)

—
—
—
4
—
—
1
—
(2) —

—
—

—
—
—
—
—

—
—

446
(4)
—
(1)
2

—
—
—
—
—

—
—
138
—
(167)

—
—

—
—
(679,785) —

85,567

856

—

1,026,077

(538,930)

—

—
—
—

—

2,279

—

2,279

—

84
—
(17)

—
—
—

84
—
(17)

—
—

—
—
—
—

—

—
—
—
—
—

—
—

—

—
110,771

150
(17)

150
110,754

866,408
260,252
32,490
(1,151)

133
—
—
—

866,541
260,252
32,490
(1,151)

—

9,333

—

9,333

—

446
—
—
—
—

—
—
—
—
—

446
—
—
—
—

—
(679,785)

562
261

562
(679,524)

488,003

956

488,959

13,500

135

—

288,375

—

288,510

—

288,510

471

—

(4)

—

51
—

1
—

—
—

(1)
(1,190)

—
—

—

—
—

—

—
(1,190)

—
—

—
(1,190)

—

11,958

—

11,958

—

11,958

—

10
—
(116)
—

—
—
—
—
(1) —
—
—

—
—
—
—

255
—
1
—

—

—
—
120
—
(116)
—
(97,421) —

—

—
—
—
—

—

255
—
—
(97,421)

—
—
—
364

255
—
—
(97,057)

Balance at December 31, 2016

99,519

$ 995

— $ — $ 1,325,481 $ (636,351)

6 $

— $ 690,125 $ 1,320 $ 691,445

The accompanying notes are an integral part of these ﬁnancial statements.

Consolidated Financial Statements FORM 10-K

F-6

MATADOR RESOURCES COMPANY

Consolidated Statements of Cash Flows

Matador Resources Company and Subsidiaries

(In thousands)

Operating activities
Net (loss) income
Adjustments to reconcile net (loss) income to net cash provided

by operating activities
Unrealized loss (gain) on derivatives
Depletion, depreciation and amortization
Accretion of asset retirement obligations
Full-cost ceiling impairment
Stock-based compensation expense
Deferred income tax (beneﬁt) provision
Amortization of debt issuance cost
Net gain on asset sales and inventory impairment
Changes in operating assets and liabilities
Accounts receivable

Lease and well equipment inventory

Prepaid expenses

Other assets
Accounts payable, accrued liabilities and other current liabilities
Royalties payable
Advances from joint interest owners
Income taxes payable
Other long-term liabilities

Net cash provided by operating activities

Investing activities

Proceeds from sale of assets
Oil and natural gas properties capital expenditures
Expenditures for other property and equipment
Business combination, net of cash acquired
Restricted cash
Restricted cash in less-than-wholly-owned subsidiaries

Net cash used in investing activities

Financing activities
Repayments of borrowings
Borrowings under Credit Agreement
Proceeds from issuance of common stock

Proceeds from issuance of senior unsecured notes
Cost to issue equity
Cost to issue senior unsecured notes
Proceeds from stock options exercised

Capital commitments from non-controlling interest owners of

less-than-wholly-owned subsidiaries

Taxes paid related to net share settlement of stock-based compensation

Net cash provided by ﬁnancing activities

Increase in cash
Cash at beginning of year
Cash at end of year

Supplemental disclosures of cash ﬂow information (Note 14)

The accompanying notes are an integral part of these ﬁnancial statements.

For the Years Ended December 31,

2016

2015

2014

$ (97,057)

$(679,524)

$ 110,754

41,238
122,048
1,182
158,633
12,362
—
1,148
(107,277)

(14,259)
(700)
(124)
490
6,611
7,495
1,000
(2,848)
4,144
134,086

5,173
(379,067)
(74,845)

—
43,098
1

(405,640)

(120,000)
120,000
288,510
184,625
(847)
(2,734)
100

39,265
178,847
734
801,166
9,450
(150,327)
852
(908)

3,633
(180)
(544)
(552)
1,375
1,654
700
2,405
489
208,535

139,836
(432,715)
(64,499)
(24,028)
(43,098)
(650)
(425,154)

(476,982)
125,000
188,720
400,000
(1,158)
(9,598)
10

(58,302)
134,737
504
—
5,524
64,242
—
—

(13,318)
(211)
(783)
1,212
607
6,663
—
39
(187)
251,481

79
(560,849)
(9,152)
—
—
(609)
(570,531)

(180,000)
320,000
181,875
—
(590)
—
43

—
(1,948)
467,706
196,152
16,732
$ 212,884

562
(1,610)
224,944
8,325
8,407
$ 16,732

150
(308)
321,170
2,120
6,287
8,407

FORM 10-K Consolidated Financial Statements

2016 ANNUAL REPORT

F-7

Notes to Consolidated Financial Statements

MATADOR RESOURCES COMPANY AND SUBSIDIARIES
December 31, 2016, 2015 and 2014

NOTE 1 — NATURE OF OPERATIONS

Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the

“Company”), is an independent energy company engaged in the exploration, development, production and acquisition
of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other
unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of
the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The
Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays
in Northwest Louisiana and East Texas. Additionally, the Company conducts midstream operations in support of
its exploration, development and production operations and provides natural gas processing, natural gas, oil and salt
water gathering services and salt water disposal services to third parties on a limited basis.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated ﬁnancial statements include the accounts of Matador Resources Company and its wholly-

owned and majority-owned subsidiaries. These consolidated ﬁnancial statements have been prepared in accordance
with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the
Company consolidates certain subsidiaries that are less-than-wholly-owned and the net income and equity attributable
to the non-controlling interest in these subsidiaries have been reported separately. The Company proportionately
consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas
exploration. All intercompany balances and transactions have been eliminated in consolidation.

Reclassiﬁcations

Certain reclassiﬁcations have been made to the prior years’ ﬁnancial statements to conform to the current year

presentation. These reclassiﬁcations had no effect on previously reported results of operations, cash ﬂows or
retained earnings. As a result of the growth of the Company’s midstream operations, these operations met the
required threshold for segment reporting at December 31, 2016. As a result, $1.8 million and $1.2 million for the
years ended December 31, 2015 and 2014, respectively, were reclassiﬁed from other income to third-party
midstream services revenues. In addition, $3.5 million and $1.4 million related to midstream operating costs for the
years ended December 31, 2015 and 2014, respectively, were reclassiﬁed from lease operating expenses to plant
and other midstream services operating expenses. These reclassiﬁcations had no effect on previously reported
results of operations, cash ﬂows or retained earnings.

Change in Accounting Principles

During the second quarter of 2016, the Company adopted Accounting Standards Update (“ASU”) 2016-09,
Compensation - Stock Compensation (Topic 718), which simpliﬁes several aspects of the accounting for employee
share-based payment transactions, including accounting for income tax, forfeitures, statutory tax withholding
requirements, classiﬁcations of awards as either equity or liability and classiﬁcation of taxes in the statement of cash
ﬂows, requiring either retrospective, modiﬁed retrospective or prospective transition. The amended guidance also
requires an entity to record excess tax beneﬁts and deﬁciencies in the income statement. The adoption of this ASU
had no impact on any period presented for (i) the Company’s ﬁnancial position or statements of operations, as the
Company currently has a valuation allowance against its net deferred tax assets, or (ii) the Company’s statements of

Notes to Consolidated Financial Statements FORM 10-K

F-8

MATADOR RESOURCES COMPANY

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

cash ﬂows, as the Company has historically accounted for taxes paid for net share settlement as a ﬁnancing activity
as required under this ASU. In addition, the Company uses historical forfeiture rates to estimate future forfeitures
attributable to the service-based vesting requirements not being met and has continued to do so upon adoption of
this ASU.

Use of Estimates

The preparation of ﬁnancial statements in conformity with U.S. GAAP requires management to make estimates

and assumptions that affect the amounts reported in the ﬁnancial statements and accompanying notes. These
estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the ﬁnancial
statements, purchase price allocations and the reported amounts of revenues and expenses during the reporting
period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the
discovery of new information may result in revised estimates. Actual results could differ from these estimates.

The Company’s consolidated ﬁnancial statements are based on a number of signiﬁcant estimates, including oil

and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative
instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The
estimates of oil and natural gas reserves quantities and future net cash ﬂows are the basis for the calculations of
depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations
and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and
based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are
prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and
Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines
by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

Restricted Cash

Restricted cash represents a portion of the cash paid for the Loving County Processing System by EnLink (as

described in Note 5) directly to a qualiﬁed intermediary to facilitate like-kind-exchange transactions for federal
income tax purposes as well as cash held by the Company’s less-than-wholly-owned subsidiaries. Not all of the cash
deposited with the qualiﬁed intermediary was used for like-kind-exchange transactions and, in January 2016, the
remaining balance of $42.1 million was returned to the Company by the qualiﬁed intermediary to be used for general
corporate purposes. By contractual agreement, the cash in the account held by the Company’s less-than-wholly-
owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital
expenditures and operations of these less-than-wholly-owned subsidiaries.

Accounts Receivable

The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see
“ —Revenue Recognition” below). Due to the nature of the markets for oil, natural gas and natural gas liquids, the
Company does not believe that the loss of any one purchaser would signiﬁcantly impact operations. In addition,
the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas
wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and
natural gas liquids or participants in oil and natural gas wells for which the Company serves as the operator.
Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are
stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been
outstanding for 60 days or more. No interest is typically charged on past due amounts.

FORM 10-K Notes to Consolidated Financial Statements

2016 ANNUAL REPORT

F-9

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the

allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the
debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay
its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts
receivable for any reporting period presented.

Lease and Well Equipment Inventory

Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or

equipment scheduled for use in future well or midstream operations.

Oil and Natural Gas Properties

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under

this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural
gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and
accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the
United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on
undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying
projects and general and administrative expenses directly related to acquisition, exploration and development
activities, but do not include any costs related to production, selling or general corporate administrative activities.
The Company capitalized $15.7 million, $6.9 million and $6.4 million of its general and administrative costs in 2016,
2015 and 2014, respectively. The Company capitalized $3.7 million, $3.9 million and $2.8 million of its interest
expense for the years ended December 31, 2016, 2015 and 2014, respectively.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon

production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded
from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for
possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment
includes consideration of the following factors, among others: the assignment of proved reserves, geological and
geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the
costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry
holes are included in the amortization base immediately upon determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or

Ceiling Test

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less

related deferred income taxes or the cost center “ceiling.” The cost center ceiling is deﬁned as the sum of:

(a)

the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves,
reduced by the estimated costs of developing these reserves, plus

(b) unproved and unevaluated property costs not being amortized, plus

(c)

the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs
being amortized, if any, less

(d)

income tax effects related to the properties involved.

Notes to Consolidated Financial Statements FORM 10-K

F-10

MATADOR RESOURCES COMPANY

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged
to operations as a full-cost ceiling impairment. The fair value of the Company’s derivative instruments is not included
in the ceiling test computation as the Company does not designate these instruments as hedge instruments for
accounting purposes.

The estimated present value of after-tax future net cash ﬂows from proved oil and natural gas reserves is
highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment.
The associated commodity prices and the applicable discount rate used in these estimates are in accordance
with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using
then-current operating and economic conditions, with no provision for price and cost changes in future periods
except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic
averages of the ﬁrst-day-of-the-month oil and natural gas prices for the previous 12-month period and a 10%
discount factor is used to determine the present value of future net revenues. For the period from January through
December 2016, these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively.
For the period from January through December 2015, these average oil and natural gas prices were $46.79 per Bbl
and $2.59 per MMBtu, respectively. For the period from January through December 2014, these average oil and
natural gas prices were $91.48 per Bbl and $4.35 per MMBtu, respectively. In estimating the present value of
after-tax future net cash ﬂows from proved oil and natural gas reserves, the average oil prices were further adjusted
by property for quality, transportation and marketing fees and regional price differentials, and the average natural
gas prices were further adjusted by property for energy content, transportation and marketing fees and regional
price differentials.

During the year ended December 31, 2016, the Company’s net capitalized costs less related deferred income

taxes exceeded the full-cost ceiling. As a result, in the ﬁrst six months of 2016, the Company recorded an
impairment charge of $158.6 million, exclusive of tax effect, to its consolidated statement of operations with the
related deferred income tax credit recorded net of a valuation allowance (see Note 7).

During the year ended December 31, 2015, the Company’s net capitalized costs less related deferred income

taxes exceeded the full-cost ceiling. As a result, throughout 2015, the Company recorded an impairment charge
of $801.2 million, exclusive of tax effect, to its consolidated statement of operations for December 31, 2015 with
the related deferred income tax credit recorded net of a valuation allowance (see Note 7).

During the year ended December 31, 2014, the Company’s full-cost ceiling exceeded the net capitalized costs
less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs
during the year ended December 31, 2014.

As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying
value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’
equity, but it has no impact on the Company’s net cash ﬂows as reported. Changes in oil and natural gas production
rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine
the Company’s actual ceiling test computation and impairment analyses in future periods.

Other Property and Equipment

Other property and equipment are recorded at historical cost and include midstream equipment and facilities,

including the Company’s pipelines, processing facilities and salt water disposal systems, and corporate assets,
including furniture, ﬁxtures, equipment, land and leasehold improvements. Midstream equipment and facilities are
depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold

FORM 10-K Notes to Consolidated Financial Statements

2016 ANNUAL REPORT

F-11

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture,
ﬁxtures and other equipment are depreciated over their useful life (ﬁve to 30 years) using the straight-line method.
Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as
incurred. See Note 3 for a detail of other property and equipment.

Asset Retirement Obligations

The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred
if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its
estimated present value, with an offsetting increase recognized in oil and natural gas properties or support
equipment and facilities on the consolidated balance sheets. Periodic accretion of the discounted value of the
estimated liability is recorded as an expense in the consolidated statements of operations.

Derivative Financial Instruments

From time to time, the Company uses derivative ﬁnancial instruments to mitigate its exposure to commodity

price risk associated with oil, natural gas and natural gas liquids prices. The Company’s derivative ﬁnancial
instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value.
The Company has elected not to apply hedge accounting for its existing derivative ﬁnancial instruments, and
as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its
consolidated statements of operations. The fair value of the Company’s derivative ﬁnancial instruments is
determined using industry-standard models that consider various inputs including: (i) quoted forward prices for
commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments,
as well as other relevant economic measures. Realized gains and realized losses from the settlement of
derivative ﬁnancial instruments and unrealized gains and unrealized losses from valuation changes in the remaining
unsettled derivative ﬁnancial instruments are reported under “Revenues” in the consolidated statements of
operations. See Note 11 for additional information about the Company’s derivative instruments.

Revenue Recognition

The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues,

whereby it recognizes revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers
regardless of whether the sales are proportionate to its ownership in the property. Under this method, revenue is
recognized at the time oil, natural gas and natural gas liquids are produced and sold, and the Company accrues
for revenue earned but not yet received. The Company recognizes midstream services revenue at the time services
have been rendered and the price is ﬁxed and determinable.

For the year ended December 31, 2016, three signiﬁcant purchasers accounted for 48% of the Company’s total

oil, natural gas and natural gas liquids revenues: Plains Marketing, L.P. (18%), Shell Trading (US) Company (17%)
and Occidental Energy Marketing, Inc. (13%). For the year ended December 31, 2015, three signiﬁcant purchasers
accounted for 59% of the Company’s total oil, natural gas and natural gas liquids revenues: Shell Trading (US)
Company (33%), Enterprise Crude Oil LLC (14%) and Sequent Energy Management, L.P. (12%). For the year ended
December 31, 2014, three signiﬁcant purchasers accounted for approximately 68% of the Company’s total oil,
natural gas and natural gas liquids revenues: Shell Trading (US) Company (45%), Enterprise Crude Oil LLC (12%)
and Enterprise Products Operating LLC (11%). Due to the nature of the markets for oil, natural gas and natural
gas liquids, the Company does not believe the loss of any one purchaser would have a material adverse impact
on the Company’s ﬁnancial condition, results of operations or cash ﬂows for any signiﬁcant period of time. At
December 31, 2016, 2015 and 2014, approximately 38%, 39% and 44%, respectively, of the Company’s accounts
receivable, including joint interest billings, related to these purchasers.

Notes to Consolidated Financial Statements FORM 10-K

F-12

MATADOR RESOURCES COMPANY

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Stock-Based Compensation

The Company grants common stock, stock options, restricted stock and restricted stock units to members of its

Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and
are generally recognized as a component of general and administrative expenses in the accompanying statements
of operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding
stock options granted under the 2003 Plan (as described and deﬁned in Note 8) as liability instruments as a result of
the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options
of the Company’s common stock.

The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options,
the closing stock price on the date of grant to measure restricted stock and restricted stock unit awards and the
Monte Carlo simulation method to measure the fair value of performance units.

The Company’s consolidated statements of operations for the years ended December 31, 2016, 2015 and 2014
include a stock-based compensation (non-cash) expense of $12.4 million, $9.5 million and $5.5 million, respectively.
This stock-based compensation expense includes common stock issuances and restricted stock units expense
totaling $1.0 million, $0.9 million and $0.3 million in 2016, 2015 and 2014, respectively, paid to members of the
Board of Directors and advisors as compensation for their services to the Company.

Income Taxes

The Company accounts for income taxes using the asset and liability approach for ﬁnancial accounting and
reporting. The Company evaluates the probability of realizing the future beneﬁts of its deferred tax assets and records
a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the beneﬁt
from the deferred tax asset will not be realized.

The Company recognizes the tax beneﬁt of an uncertain tax position only if it is more likely than not that the tax
position will be sustained upon examination by the taxing authorities based on the technical merits of the position.
For tax positions meeting the more likely than not threshold, the amount recognized in the ﬁnancial statements is
the beneﬁt that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax
authority. At December 31, 2016, 2015 and 2014, the Company had not established any reserves for, nor recorded
any unrecognized tax beneﬁts related to, uncertain tax positions.

When necessary, the Company would include interest assessed by taxing authorities in “Interest expense”

and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The
Company did not record any interest or penalties related to income taxes for the years ended December 31, 2016,
2015 and 2014.

Allocation of Purchase Price in Business Combinations

As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties.

The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on
their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore,
while the consideration to be paid may be ﬁxed, the fair value of the assets acquired and liabilities assumed is
subject to change during the period between the announcement date and the acquisition date. The most signiﬁcant
estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and
unproved and unevaluated properties. As the allocation of the purchase price is subject to signiﬁcant estimates and
subjective judgments, the accuracy of this assessment is inherently uncertain.

FORM 10-K Notes to Consolidated Financial Statements

2016 ANNUAL REPORT

F-13

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Earnings (Loss) Per Common Share

The Company reports basic earnings (loss) per common share, which excludes the effect of potentially dilutive

securities, and diluted earnings (loss) per common share, which includes the effect of all potentially dilutive
securities, unless their impact is anti-dilutive.

The following are reconciliations of the numerators and denominators used to compute the Company’s basic and

diluted earnings per common share as reported for the years ended December 31, 2016, 2015 and 2014 (in
thousands, except per share data).

Year Ended December 31,

2016

2015

2014

Net (loss) income attributable to Matador Resources Company shareholders —

numerator

$ (97,421)

$ (679,785)

$110,771

Weighted average common shares outstanding — denominator

Basic
Dilutive effect of options, restricted stock units and preferred shares
Diluted weighted average common shares outstanding

Earnings (loss) per common share attributable to
Matador Resources Company shareholders

Basic

Diluted

91,273
—
91,273

81,537
—
81,537

70,229
677
70,906

(1.07)

(8.34)

1.58

1.56

A total of 2.9 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock
units were excluded from the calculations above for the year ended December 31, 2016 because their effects were
anti-dilutive. Additionally, 1.0 million restricted shares, which are participating securities, were excluded from the
calculations above for the year ended December 31, 2016 as the security holders do not have the obligation to share
in the losses of the Company.

A total of 2.4 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock
units were excluded from the calculations above for the year ended December 31, 2015 because their effects were
anti-dilutive. Additionally, 0.9 million restricted shares, which are participating securities, were excluded from the
calculations above for the year ended December 31, 2015 as the security holders do not have the obligation to share
in the losses of the Company.

Credit Risk

The Company’s cash is held in ﬁnancial institutions and at times these amounts exceed the insurance limits of
the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks
are minimal based on the reputation and history of the institutions selected.

The Company uses derivative ﬁnancial instruments to mitigate its exposure to oil, natural gas and natural gas

liquids price volatility. These transactions expose the Company to potential credit risk from its counterparties.
The Company manages counterparty credit risk through established internal derivatives policies that are reviewed
on an ongoing basis. Additionally, all of the Company’s commodity derivative contracts at December 31, 2016 were
with Comerica Bank, The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and SunTrust Bank (or
afﬁliates thereof), parties that are lenders (or afﬁliates thereof) under the Company’s Credit Agreement.

Notes to Consolidated Financial Statements FORM 10-K

F-14

MATADOR RESOURCES COMPANY

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Accounts receivable constitute the principal component of additional credit risk to which the Company may
be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the ﬁnancial
condition and payment history of its purchasers and joint interest partners.

Recent Accounting Pronouncements

Revenue from Contracts with Customers. In May 2014, the Financial Accounting Standards Board (“FASB”)

issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which speciﬁes how and when to
recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to
improve, and converge with international standards, the ﬁnancial reporting requirements for revenue from contracts
with customers. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09
for one year to ﬁscal years beginning after December 15, 2017. Early adoption is permitted for ﬁscal years beginning
after December 15, 2016. In May 2016, the FASB issued ASU 2016-11, which rescinds guidance from the SEC on
accounting for gas balancing arrangements and will eliminate the use of the entitlements method. Entities have the
option of using either a full retrospective or modiﬁed approach to adopt the new standards. In December 2016,
the FASB issued ASU 2016-20, which clariﬁes disclosure requirements in ASU 2014-09. The Company will adopt
the new guidance effective January 1, 2018. The Company is evaluating the new guidance, including (i) identiﬁcation
of revenue streams, (ii) review of contracts and procedures currently in place and (iii) which adoption method it
will use.

Recognition and Measurement of Financial Assets and Financial Liabilities. In January 2016, the FASB
issued 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which changes certain
guidance related to the recognition, measurement, presentation and disclosure of ﬁnancial instruments. This
update is effective for ﬁscal years beginning after December 15, 2017, including interim periods within those
ﬁscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions.
We do not anticipate the adoption of this ASU will have a material impact on our consolidated ﬁnancial statements.

Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires the recognition
of lease assets and lease liabilities by lessees for those leases classiﬁed as operating leases under previous U.S.
GAAP. This ASU will become effective for ﬁscal years beginning after December 15, 2018 with early adoption
permitted. Entities are required to recognize and measure leases at the beginning of the earliest period presented
using a modiﬁed retrospective approach. The modiﬁed retrospective approach includes a number of optional practical
expedients that entities may elect to apply. These practical expedients relate to the identiﬁcation and classiﬁcation
of leases that commenced before the effective date, initial direct costs for leases that commenced before
the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to
purchase the underlying asset. The Company is currently evaluating the impact of the adoption of this ASU on its
consolidated ﬁnancial statements.

Statement of Cash Flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows

(Topic 230), which speciﬁes that a statement of cash ﬂows explain the change during the period in the total of cash,
cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. This ASU will
become effective for ﬁscal years beginning after December 15, 2017, and interim periods within those ﬁscal years.
Early adoption is permitted, including adoption in an interim period. The update should be applied using a
retrospective transition method to each period presented. The Company believes that the impact of the adoption
of this ASU will change the presentation of its beginning and ending cash balances on its Consolidated Statements
of Cash Flows and eliminate the presentation of changes in restricted cash balances from investing activities on
its Consolidated Statements of Cash Flows.

FORM 10-K Notes to Consolidated Financial Statements

2016 ANNUAL REPORT

F-15

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued

Clarifying the Deﬁnition of a Business. In January 2017, the FASB issued ASU 2017-01, Business

Combinations (Topic 805), which speciﬁes the minimum inputs and processes required for an integrated set of
assets and activities to meet the deﬁnition of a business. This ASU will become effective for ﬁscal years
beginning after December 15, 2017 with early adoption permitted. Entities are required to apply guidance
prospectively upon adoption. The Company is currently evaluating the impact of the adoption of this ASU on its
consolidated ﬁnancial statements.

NOTE 3 — PROPERTY AND EQUIPMENT

The following table presents a summary of the Company’s property and equipment balances as of December 31,

2016 and 2015 (in thousands).

Oil and natural gas properties

Evaluated (subject to amortization)
Unproved and unevaluated (not subject to amortization)
Total oil and natural gas properties
Accumulated depletion
Net oil and natural gas properties

Other property and equipment

Midstream equipment and facilities
Furniture, ﬁxtures and other equipment
Software
Land
Leasehold improvements
Total other property and equipment
Accumulated depreciation

Net other property and equipment
Net property and equipment

December 31,

2016

2015

$ 2,408,305
479,736
2,888,041
(1,850,882)
1,037,159

145,662
5,487
3,206
1,437
5,003
160,795
(13,429)
147,366
$ 1,184,525

$ 2,122,174
387,504
2,509,678
(1,574,040)
935,638

78,564
2,918
2,193
1,539
1,173
86,387
(9,619)
76,768
$ 1,012,406

The following table provides a breakdown of the Company’s unproved and unevaluated property costs not
subject to amortization as of December 31, 2016 and the year in which these costs were incurred (in thousands).

Description

Costs incurred for

Property acquisition

Development wells

Total

2016

2015

2014

2013 and prior

Total

$ 126,857
19,017
13,086
$ 158,960

$ 236,507
3,375
1,218
$ 241,100

$ 55,258
34
730
$ 56,022

$ 23,654
—
—
$ 23,654

$ 442,276
22,426
15,034
$ 479,736

but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs
associated with developing oil and natural gas prospects on these properties. Property acquisition costs are
transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves
are established or impairment is determined. Unproved and unevaluated properties are assessed for possible
impairment on a periodic basis based upon changes in operating or economic conditions.

Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2016 are

related primarily to the Company’s leasehold and mineral acquisitions in the Wolfcamp and Bone Spring plays in
the Delaware Basin in Southeast New Mexico and West Texas during the past four years. These costs include, in
particular, the cost of the acreage acquired as part of the HEYCO Merger (as described and deﬁned in Note 5)

Notes to Consolidated Financial Statements FORM 10-K

F-16

MATADOR RESOURCES COMPANY

NOTE 3 — PROPERTY AND EQUIPMENT — Continued

in 2015. These costs are associated with acreage for which proved reserves have yet to be assigned. A signiﬁcant
portion of these costs are associated with properties which are held by production or have automatic lease renewal
options. As the Company drills wells and assigns proved reserves to these properties or determines that certain
portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the
amortization base.

Costs excluded from amortization also include those costs associated with exploration and development

wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an
ongoing basis as these wells are completed and proved reserves are established or conﬁrmed. These costs
totaled $37.5 million at December 31, 2016. Of this total, $22.4 million was associated with exploration wells
and $15.0 million was associated with development wells. The Company anticipates that most of the $37.5 million
associated with these wells in progress at December 31, 2016 will be transferred to the amortization base
during 2017.

NOTE 4 — ASSET RETIREMENT OBLIGATIONS

In general, the Company’s asset retirement obligations relate to future costs associated with plugging and

abandonment of its oil and natural gas wells, removal of pipelines, equipment and facilities from leased acreage and
returning such land to its original condition. The amounts recognized are based on numerous estimates and
assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inﬂation
rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in
these estimates and assumptions or if federal or state regulators enact new plugging and abandonment
requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company
includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are
different from the estimated liability.

The following table summarizes the changes in the Company’s asset retirement obligations for the years ended

December 31, 2016 and 2015 (in thousands).

Beginning asset retirement obligations
Liabilities incurred during period
Liabilities settled during period
Revisions in estimated cash ﬂows
Accretion expense
Ending asset retirement obligations

Less: current asset retirement obligations (1)
Long-term asset retirement obligations

(1)

Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2016 and 2015.

Year Ended December 31,

2016

2015

$ 15,420
1,791
(375)
2,622
1,182
20,640
(915)

$ 19,725

$11,951
4,508
(588)
(1,185)
734
15,420
(254)
$15,166

FORM 10-K Notes to Consolidated Financial Statements

2016 ANNUAL REPORT

F-17

NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES

Business Combinations

On February 27, 2015, the Company completed a business combination with Harvey E. Yates Company

(“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., through a merger of HEYCO with and into a wholly-owned
subsidiary of Matador (the “HEYCO Merger”). In the HEYCO Merger, the Company obtained certain oil and
natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico,
consisting of approximately 58,600 gross (18,200 net) acres strategically located between the Company’s existing
acreage in its Ranger and Rustler Breaks asset areas. HEYCO, headquartered in Roswell, New Mexico, was
privately-owned prior to the transaction.

As consideration for the business combination, Matador paid approximately $33.6 million in cash and assumed

debt obligations and issued 3,300,000 shares of Matador common stock and 150,000 shares of a new series of
Matador Series A Convertible Preferred Stock (“Series A Preferred Stock”) to HEYCO Energy Group, Inc.
(convertible into ten shares of common stock for each one share of Series A Preferred Stock upon the effectiveness
of an amendment to the Company’s Amended and Restated Certiﬁcate of Formation to increase the number of
authorized shares of common stock; the Series A Preferred Stock converted to common stock on April 6, 2015).
Matador incurred an additional $4.5 million for customary purchase price adjustments, including adjusting for
production, revenues and operating and capital expenditures from September 1, 2014 to closing. The consideration
paid and the liabilities assumed, including deferred tax liabilities of approximately $76.8 million and other liabilities
of approximately $4.5 million, represent a total purchase price of $223.5 million. The HEYCO Merger was accounted
for using the acquisition method under ASC Topic 805, “Business Combinations,” which requires the assets
acquired and liabilities assumed to be recorded at fair value as of the respective acquisition date.

The majority of the assets acquired in the HEYCO Merger were in the form of non-producing acreage.

The producing wells acquired in the HEYCO Merger did not have a material impact on the Company’s revenues or
results of operations for the year ended December 31, 2015. During the year ended December 31, 2015, the
Company incurred approximately $2.5 million of transaction costs associated with the HEYCO Merger, which were
included in “General and administrative” costs in the consolidated statement of operations.

Divestitures

On October 1, 2015, the Company completed the sale of its wholly-owned subsidiary that owned certain natural

gas gathering and processing assets in the Delaware Basin in Loving County, Texas (the “Loving County
Processing System”) to an afﬁliate of EnLink Midstream Partners, LP (“EnLink”). The Loving County Processing
System included a cryogenic natural gas processing plant with approximately 35 MMcf per day of inlet capacity
(the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline which connects the
Company’s gathering system to the Wolf Processing Plant.

Pursuant to the terms of the transaction, EnLink paid approximately $143.4 million and the Company received net

proceeds of approximately $139.8 million, after deducting customary purchase price adjustments of approximately
$3.6 million. In conjunction with the sale of the Loving County Processing System, the Company dedicated a
signiﬁcant portion of its leasehold interests in Loving County as of the closing date pursuant to a 15-year ﬁxed-fee
natural gas gathering and processing agreement and provided a volume commitment in exchange for priority one
service. See Note 13 for more information related to this agreement.

Notes to Consolidated Financial Statements FORM 10-K

F-18

MATADOR RESOURCES COMPANY

NOTE 5 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued

Due to the terms of the agreement, the transaction was accounted for as a sale and leaseback transaction; the

carrying value of the net assets sold of approximately $31.0 million was removed from the consolidated balance
sheet as of December 31, 2015 and the resulting difference of approximately $108.4 million between the net
proceeds received less closing costs of $0.4 million and the basis of the assets sold was recorded as deferred gain
on plant sale and was to be recognized as a gain on asset sales over the 15-year term of the gathering and
processing agreement.

During the fourth quarter of 2016, EnLink completed construction of another processing plant in Loving County,

Texas. Upon completion and successful testing of this new plant, as allowed under the gathering and processing
agreement, EnLink is now processing the Company’s natural gas produced in this area at the new plant. As such,
the gathering and processing agreement the Company entered into with EnLink is no longer considered a lease, and
accordingly, the Company recognized the unamortized gain on the sale of $107.3 million in the consolidated
statement of operations for the year ended December 31, 2016.

The Company can, at its option and upon mutual agreement with EnLink, dedicate any future leasehold

acquisitions in Loving County to EnLink. In addition, the Company retained its natural gas gathering system up to
a central delivery point and its other midstream assets in the area, including oil and water gathering systems and
salt water disposal wells. On February 17, 2017 these assets were contributed to the Joint Venture (as described
and deﬁned in Note 18).

NOTE 6 — DEBT

Credit Agreement

On September 28, 2012, the Company amended and restated its revolving credit agreement with the lenders party
thereto (the “Credit Agreement”), which increased the maximum facility amount from $400.0 million to $500.0 million.
MRC Energy Company, which is a subsidiary of Matador and directly or indirectly holds the ownership interests in
the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower
under the Credit Agreement. Borrowings are secured by mortgages on at least 80% of the Company’s proved oil
and natural gas properties and by the equity interests of MRC Energy Company’s wholly-owned subsidiaries,
which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the
parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement
(or afﬁliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of
MRC Energy Company.

The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by

the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at
December 31 and June 30 of each year, respectively. Both the Company and the lenders may request an unscheduled
redetermination of the borrowing base once each between scheduled redetermination dates. On October 31, 2016,
the borrowing base was increased from $300.0 million to $400.0 million based on the lenders’ review of the
Company’s proved oil and natural gas reserves at June 30, 2016 using commodity price estimates prescribed by the
lenders. This borrowing base increase was primarily attributable to increases in both the Company’s proved
reserves volumes and increases in oil and natural gas prices in the latter part of 2016. All other provisions of the
Credit Agreement remained unchanged. This October 2016 redetermination constituted the regularly scheduled
November 1 redetermination. The Credit Agreement matures on October 16, 2020.

FORM 10-K Notes to Consolidated Financial Statements

2016 ANNUAL REPORT

F-19

NOTE 6 — DEBT — Continued

In the event of a borrowing base increase, the Company is required to pay a fee to the lenders equal to a
percentage of the amount of the increase, which is determined based on market conditions at the time of the
borrowing base increase. Total deferred loan costs were $1.3 million at December 31, 2016, and these costs are
being amortized over the term of the Credit Agreement, which approximates amortization of these costs using
the effective interest method. If, upon a redetermination of the borrowing base, the borrowing base were to be less
than the outstanding borrowings under the Credit Agreement at any time, the Company would be required to
provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an
amount sufﬁcient to cover such excess or to repay the deﬁcit in equal installments over a period of six months.

During the year ended December 31, 2016, using a portion of the net proceeds from the December 2016 senior

unsecured notes offering and the public offering of our common stock discussed herein, the Company repaid a
total of $120.0 million of its outstanding borrowings under the Credit Agreement. At December 31, 2016, the
Company had no borrowings outstanding under the Credit Agreement and approximately $0.8 million in outstanding
letters of credit issued pursuant to the Credit Agreement. At February 22, 2017, the Company continued to have
no borrowings outstanding under the Credit Agreement and approximately $0.8 million in outstanding letters of credit
issued pursuant to the Credit Agreement.

Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If the

Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the
prime rate for such day or (ii) the Federal Funds Effective Rate (as deﬁned in the Credit Agreement) on such day,
plus 0.50% or (iii) the daily adjusting LIBOR rate (as deﬁned in the Credit Agreement) plus 1.0% plus, in each case,
an amount from 0.50% to 1.50% of such outstanding loan depending on the level of borrowings under the Credit
Agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to
(i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate
during such interest calculation period at which Royal Bank of Canada (“RBC”) is required to maintain reserves on
Eurocurrency Liabilities (as deﬁned in Regulation D of the Board of Governors of the Federal Reserve System)
plus (ii) an amount from 1.50% to 2.50% of such outstanding loan depending on the level of borrowings under the
Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as
designated by the Company.

A commitment fee of 0.375% to 0.50%, depending on the unused availability under the Credit Agreement, is
also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred ﬁnancing
costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as
interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the
Company to maintain a debt to EBITDA ratio, which is deﬁned as total debt outstanding divided by a rolling four
quarter EBITDA calculation, of 4.25 or less.

Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s ability

to take certain actions, including, but not limited to, the following:

(cid:85)

incur indebtedness or grant liens on any of the Company’s assets;

(cid:85) enter into commodity hedging agreements;

(cid:85) declare or pay dividends, distributions or redemptions;

(cid:85) merge or consolidate;

(cid:85) make any loans or investments;

Notes to Consolidated Financial Statements FORM 10-K

F-20

MATADOR RESOURCES COMPANY

NOTE 6 — DEBT — Continued

(cid:85) engage in transactions with afﬁliates;

(cid:85) engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets; and

(cid:85)

take certain actions with respect to the Company’s senior unsecured notes.

If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity
of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the
following events:

(cid:85)

failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under
any letter of credit when due or any fees or other amounts within certain grace periods;

failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other
loan documents, subject, in certain instances, to certain grace periods;

(cid:85) bankruptcy or insolvency events involving the Company or its subsidiaries; and

(cid:85) a change of control, as deﬁned in the Credit Agreement.

The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2016.

Senior Unsecured Notes

On April 14, 2015, Matador issued $400.0 million of 6.875% senior notes due 2023 (the “Original Notes”) in a

private placement. The Original Notes are Matador’s senior unsecured obligations, are redeemable as described
below and were issued at par value. The net proceeds were used to pay down a portion of the outstanding
borrowings under the Credit Agreement and the debt assumed in connection with the HEYCO Merger. The Original
Notes mature on April 15, 2023 and interest is payable semi-annually in arrears on April 15 and October 15 of
each year.

On October 21, 2015, and pursuant to a registered exchange offer, the Company exchanged all of the privately

placed Original Notes for a like principal amount of 6.875% senior notes due 2023 that have been registered
under the Securities Act (the “Registered Notes”). The terms of such Registered Notes are substantially the same
as the terms of the Original Notes except that the transfer restrictions, registration rights and provisions for
additional interest relating to the Original Notes do not apply to the Registered Notes.

On December 9, 2016, Matador issued $175.0 million of 6.875% senior notes due 2023 (the “Additional Notes”

and, collectively with the Registered Notes, the “Notes”) in a private placement (the “Notes Offering”). The
Additional Notes were issued pursuant to and are governed by the same indenture governing the Original Notes
(the “Indenture”). The Additional Notes were issued at 105.5% of par, plus accrued interest from October 15, 2016,
resulting in an effective interest rate of 5.5%. We received net proceeds from the Notes Offering of approximately
$181.5 million, including the issue premium, but after deducting the initial purchasers’ discounts and estimated
offering expenses and excluding accrued interest paid by buyers of the Additional Notes. A portion of the net
proceeds of the Notes Offering, along with the proceeds from the December 2016 public offering of our common
stock, have been used to partially fund certain acreage acquisitions and midstream asset development, to repay
outstanding borrowings under the Credit Agreement and for general corporate purposes, including capital
expenditures associated with the addition of a fourth drilling rig. The Notes are our senior unsecured obligations and
are redeemable as described below. The Notes mature on April 15, 2023, and interest is payable semi-annually in
arrears on April 15 and October 15 of each year.

FORM 10-K Notes to Consolidated Financial Statements

2016 ANNUAL REPORT

F-21

NOTE 6 — DEBT — Continued

On or after April 15, 2018, Matador may redeem all or a portion of the Notes at any time or from time to time at

the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid
interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning on April 15 of
the years indicated.

Year

2018
2019
2020
2021 and thereafter

Redemption Price

105.156%
103.438%
101.719%
100.000%

At any time prior to April 15, 2018, Matador may redeem up to 35% of the aggregate principal amount of the
Notes with net proceeds from certain equity offerings at a redemption price of 106.875% of the principal amount
of the Notes, plus accrued and unpaid interest, if any, to the redemption date; provided that (i) at least 65% in
aggregate principal amount of the Notes (including any additional notes) originally issued remains outstanding
immediately after the occurrence of such redemption (excluding Notes held by Matador and its subsidiaries)
and (ii) each such redemption occurs within 180 days of the date of the closing of the related equity offering.

In addition, at any time prior to April 15, 2018, Matador may redeem all or part of the Notes at a redemption price

equal to the sum of (i) the principal amount thereof, plus (ii) the excess, if any, of (a) the present value at such
time of (1) the redemption price of such Notes at April 15, 2018 plus (2) any required interest payments due on such
Notes through April 15, 2018 discounted to the redemption date on a semi-annual basis using a discount rate
equal to the Treasury Rate (as deﬁned in the Indenture) plus 50 basis points, over (b) the principal amount of such
Notes, plus (iii) accrued and unpaid interest, if any, to the redemption date.

Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take

certain actions, including, but not limited to, the following:

(cid:85)

incur or guarantee additional debt or issue certain types of preferred stock;

(cid:85) pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated

indebtedness;

(cid:85)

transfer or sell assets;

(cid:85) make certain investments;

(cid:85) create certain liens;

(cid:85) enter into agreements that restrict dividends or other payments from its Restricted Subsidiaries (as deﬁned

in the Indenture) to the Company;

(cid:85) consolidate, merge or transfer all or substantially all of its assets;

(cid:85) engage in transactions with afﬁliates; and

(cid:85) create unrestricted subsidiaries.

Notes to Consolidated Financial Statements FORM 10-K

F-22

MATADOR RESOURCES COMPANY

NOTE 6 — DEBT — Continued

In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador,

any Restricted Subsidiary that is a Signiﬁcant Subsidiary (as deﬁned in the Indenture) or any group of Restricted
Subsidiaries that, taken together, would constitute a Signiﬁcant Subsidiary, all outstanding Notes will become due
and payable immediately without further action or notice. If any other event of default occurs and is continuing,
the trustee or the holders of at least 25% in principal amount of the then outstanding Notes may declare all the
Notes to be due and payable immediately. Events of default include, but are not limited to, the following events:

(cid:85) default for 30 days in the payment when due of interest on the Notes;

(cid:85) default in the payment when due of the principal of, or premium, if any, on the Notes;

(cid:85)

failure by Matador to comply with its obligations to offer to purchase or purchase Notes when required
pursuant to the change of control or asset sale provisions of the Indenture or Matador’s failure to comply
with the covenant relating to merger, consolidation or sale of assets;

failure by Matador for 180 days after notice to comply with its reporting obligations under the Indenture;

failure by Matador for 60 days after notice to comply with any of the other agreements in the Indenture;

(cid:85) payment defaults and accelerations with respect to other indebtedness of Matador and its Restricted

Subsidiaries in the aggregate principal amount of $25.0 million or more;

(cid:85)

failure by Matador or any Restricted Subsidiary to pay certain ﬁnal judgments aggregating in excess of
$25.0 million within 60 days;

(cid:85) any subsidiary guarantee by a guarantor ceasing to be in full force and effect, being declared null and void

in a judicial proceeding or being denied or disafﬁrmed by its maker; and

(cid:85) certain events of bankruptcy or insolvency with respect to Matador or any Restricted Subsidiary that

is a Signiﬁcant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a
Signiﬁcant Subsidiary.

NOTE 7 — INCOME TAXES

Deferred tax assets and liabilities are the result of temporary differences between the ﬁnancial statement

carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31,
2016 and 2015, respectively, is as follows (in thousands).

Deferred tax assets

Unrealized loss on derivatives
Net operating loss carryforwards
Alternative minimum tax carryforward
Percentage depletion carryover
Property and equipment
Deferred gain on sale leaseback transaction
Other
Total deferred tax assets
VV
Total deferred tax assets, net of valuation allowance

Valuation allowance on deferred tax assets

Deferred tax liabilities

Unrealized gain on derivatives
Other
Total deferred tax liabilities
Net deferred tax liabilities

FORM 10-K Notes to Consolidated Financial Statements

December 31,

2016

2015

8,734
137,757
8,633
2,595
44,391
—
—
202,110
(190,255)
11,855

—
79,208
9,785
2,442
42,757
32,831
7,396
174,419
(154,320)
20,099

(3,800)
(8,055)
(11,855)

—

(5,699)
(14,400)
(20,099)
—

2016 ANNUAL REPORT

F-23

NOTE 7 — INCOME TAXES — Continued

At December 31, 2016, the Company had net operating loss carryforwards of $375.9 million for federal income
tax purposes and $6.2 million for state income tax purposes available to offset future taxable income, as limited by
the applicable provisions, and which expire at various dates beginning December 31, 2027 for the federal net
operating loss carryforwards. The state net operating loss carryforwards began expiring at various dates beginning
December 31, 2013 for the State of New Mexico; however, the signiﬁcant portion of the Company’s state net
operating loss carryforwards expire beginning in 2027.

As a result of the net capitalized costs of the Company’s oil and natural gas properties less related deferred
income taxes exceeding the full-cost ceiling during the years ended December 31, 2016 and 2015, the Company
recorded an impairment charge of $158.6 million and $801.2 million, respectively, exclusive of tax effect, to the net
capitalized costs of its oil and natural gas properties. At December 31, 2016 and 2015, the Company’s deferred
tax assets exceeded its deferred tax liabilities due to the deferred tax assets generated by the impairment charges
recorded in 2015 and 2016. As a result, at December 31, 2016 and 2015, the Company maintained a valuation
allowance against the Company’s federal and state deferred tax assets. The valuation allowance will continue to be
recognized until the realization of future tax beneﬁts are more likely than not to be utilized.

The current income tax provision for the years ended December 31, 2016, 2015 and 2014, respectively, was

comprised of the following (in thousands).

Current income tax provision

State income tax
Federal alternative minimum tax

Net current income tax (beneﬁt) provision

Year Ended December 31,

2016

2015

2014

108
(1,144)
$ (1,036)

371
2,588
2,959

—
133
133

Reconciliations of the tax (beneﬁt) expense computed at the statutory federal rate to the Company’s total

income tax (beneﬁt) provision for the years ended December 31, 2016, 2015 and 2014, respectively, is as follows
(in thousands).

Federal tax (beneﬁt) expense at statutory rate (1)
State income tax
Permanent differences (2)
Federal alternative minimum tax
Change in federal valuation allowance
Change in state valuation allowance

Net deferred income tax (beneﬁt) provision
Net current income tax (beneﬁt) provision
Total income tax (beneﬁt) provision

Year Ended December 31,

2016

2015

2014

$ (34,333)
539
(499)
1,144
33,688
(539)
—
(1,036)
$ (1,036)

$ (289,412)
(13,215)
698
(2,588)
145,777
8,413
(150,327)
2,959
$ (147,368)

$ 61,301
2,707
397
(133)
—
(30)
64,242
133
$ 64,375

(1) The statutory federal tax rate was 35% for the years ended December 31, 2016, 2015 and 2014.

(2) Amount is primarily attributable to stock-based compensation.

The Company ﬁles a United States federal income tax return and several state tax returns, a number of which
remain open for examination. The earliest tax year open for examination for the federal, the State of New Mexico
and the State of Louisiana tax returns is 2012. The earliest tax year open for examination by the State of Texas is
2009. During the year ended December 31, 2016, the Company’s 2009 and 2010 franchise tax returns were under
examination by the State of Texas. This examination has been completed with no additional tax due; however,
the examination has not been formally closed. In addition, as of December 31, 2016, the Company’s 2013 federal

Notes to Consolidated Financial Statements FORM 10-K

F-24

MATADOR RESOURCES COMPANY

NOTE 7 — INCOME TAXES — Continued

income tax return was under examination by the Internal Revenue Service. This examination has been completed
with no additional tax due; however, the examination has not been formally closed.

The Company has evaluated all tax positions for which the statute of limitations remains open and believes that
the material positions taken would more likely than not be sustained by examination. Therefore, at December 31,
2016, the Company had not established any reserves for, nor recorded any unrecognized beneﬁts related to,
uncertain tax positions.

NOTE 8 — STOCK-BASED COMPENSATION

Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards

In 2003, the Company’s Board of Directors and shareholders approved the 2003 Stock and Incentive Plan (the
“2003 Plan”). The 2003 Plan, as amended, provided that a maximum of 3,481,569 shares of common stock in the
aggregate could be issued pursuant to options or restricted stock grants. The persons eligible to receive awards
under the 2003 Plan included employees, directors, contractors or advisors of the Company.

In 2012, the Board of Directors adopted and shareholders approved the 2012 Long-Term Incentive Plan (as

subsequently amended and restated, the “2012 Incentive Plan”). As of December 31, 2016, the 2012 Incentive Plan
provided for a maximum of 8,700,000 shares of common stock in the aggregate that may be issued by the
Company pursuant to grants of stock options, restricted stock, stock appreciation rights, restricted stock units or
other performance awards. The persons eligible to receive awards under the 2012 Incentive Plan include
employees, directors, contractors or advisors of the Company. The primary purpose of the 2012 Incentive Plan is to
attract and retain key employees, key contractors and outside directors and advisors of the Company. With the
adoption of the 2012 Incentive Plan, the Company does not plan to make any future awards under the 2003 Plan,
but the 2003 Plan will remain in place until all awards outstanding under that plan have been settled.

The 2003 Plan and the 2012 Incentive Plan are administered by the independent members of the Board of

Directors, which, upon recommendation of the Compensation Committee of the Board of Directors, determine the
number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants
and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option
exercises or restricted share grants. All stock-based compensation awards granted since 2012 have been granted
under the 2012 Incentive Plan and are equity-based awards for which the fair value is ﬁxed at the grant date, while
all stock-based compensation awards granted prior to January 1, 2012 were granted under the 2003 Plan and are
liability-based awards for which the fair value is remeasured at each reporting period.

Stock Options

Historically, stock option awards have been granted to purchase the Company’s common stock at an exercise
price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical
maximum term of ﬁve or ten years.

FORM 10-K Notes to Consolidated Financial Statements

2016 ANNUAL REPORT

F-25

NOTE 8 — STOCK-BASED COMPENSATION — Continued

The fair value of stock option awards outstanding under the 2003 Plan was estimated using the following

weighted average assumptions at December 31, 2016, 2015 and 2014.

Stock option pricing model
Expected option life
Risk-free interest rate
Volatility
VV
Dividend yield
Estimated forfeiture rate

2016

2015

2014

Black Scholes Merton
3.14 years
1.70%
47.07%
—%
—%

Black Scholes Merton
0.39 years
0.64%
91.98%
—%
—%

Black Scholes Merton
1.51 years
0.74%
55.14%
—%
—%

The weighted average grant date fair value for stock option awards outstanding under the 2012 Incentive Plan

was estimated using the following weighted average assumptions during the years ended December 31, 2016,
2015 and 2014.

Stock option pricing model
Expected option life
Risk-free interest rate
Volatility
VV
Dividend yield
Estimated forfeiture rate
Weighted average fair value of stock option

2016

2015

2014

Black Scholes Merton
3.96 years
1.08%
45.68%
—%
1.16%

Black Scholes Merton
4.00 years
1.15%
56.89%
—%
3.21%

Black Scholes Merton
3.99 years
1.21%
51.47%
—%
4.28%

awards granted during the year

$5.65

$9.90

$9.45

The Company estimated the future volatility of its common stock using the historical value of its stock for a
period of time commensurate with the expected term of the stock option. The expected term was estimated using
the simpliﬁed method outlined in Staff Accounting Bulletin Topic 14. The risk-free interest rate is the rate for constant
yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award.

Summarized information about stock options outstanding at December 31, 2016 under the 2003 Plan and the

2012 Incentive Plan is as follows.

Options outstanding at December 31, 2015

Options granted
Options exercised
Options forfeited
Options expired

Options outstanding at December 31, 2016

Number of
options
(in thousands)

Weighted
average
exercise price

2,363
668
(114)
(28)
(2)
2,887

$15.40
$ 15.51
$ 10.12
$ 19.73
$ 22.66
$ 15.59

Range of exercise prices

$8.18 - $9.55
$10.49 - $17.80
$18.77 - $22.70
$23.40 - $27.33

Options outstanding at
December 31, 2016

Options exercisable at

December 31, 2016

Shares
outstanding
(in thousands)

Weighted average
remaining
contractual life

Weighted average
exercise price

Shares
exercisable
(in thousands)

Weighted
average
exercise price

816
925
862
284

1.30
2.87
3.05
2.26

$ 8.30
$ 13.55
$ 21.84
$ 24.22

484
302
65
112

$ 8.35
$ 10.58
$ 21.21
$ 23.49

Notes to Consolidated Financial Statements FORM 10-K

F-26

MATADOR RESOURCES COMPANY

NOTE 8 — STOCK-BASED COMPENSATION — Continued

At December 31, 2016, the aggregate intrinsic value was $29.4 million for outstanding options and $13.6 million
for exercisable options, based on the Company’s quoted closing market price of $25.76 per share on that date. The
remaining weighted average contractual term of exercisable options at December 31, 2016 was 1.19 years.

The total intrinsic value of options exercised during the years ended December 31, 2016, 2015 and 2014 was

$1.6 million, $1.3 million and $0.2 million, respectively. The tax related beneﬁt realized from the exercise of
stock options totaled $0.5 million, $0.3 million and $0.1 million for the years ended December 31, 2016, 2015 and
2014, respectively.

During the years ended December 31, 2016, 2015 and 2014, the Company recognized $5.9 million, $4.7 million
and $2.5 million, respectively, in stock-based compensation expense attributable to stock options. At December 31,
2016, 2015 and 2014, the Company had recorded $1.4 million, zero and $1.4 million of long-term liabilities and
zero, $1.0 million and zero of current liabilities, respectively, related to its outstanding liability-based stock options.
The Company did not settle any liability-based awards in cash for the years ended December 31, 2016, 2015 and
2014, respectively.

At December 31, 2016, the total remaining unrecognized compensation expense related to unvested stock

options was approximately $6.9 million and the weighted average remaining requisite service period (vesting period)
of all unvested stock options was 1.90 years.

The fair value of options vested during 2016, 2015 and 2014 was $3.0 million, $1.3 million and $1.5 million,

respectively.

Restricted Stock, Restricted Stock Units and Common Stock

The Company has granted stock, restricted stock and restricted stock unit awards to employees, outside

directors and advisors of the Company under the 2003 Plan and the 2012 Incentive Plan. The stock and restricted
stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The restricted stock units are
issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. One
current director elected to defer the issuance of his awards in 2015, 2014 and 2013. All awards granted in 2016,
2015 and 2014 were service based awards and vest over the service period, which is one to four years. All
restricted stock and restricted stock unit awards outstanding at December 31, 2016 were granted under the 2012
Incentive Plan.

A summary of the non-vested restricted stock and restricted stock units as of December 31, 2016 is presented

below (in thousands, except fair value).

Non-vested restricted stock
and restricted stock units

Non-vested at December 31, 2015
Granted
Vested
VV
Forfeited
Non-vested at December 31, 2016

Restricted Stock

Restricted Stock Units

Weighted
average
fair value

$ 17.64
$ 18.55
$ 16.05
$ 20.49
$ 18.23

854
472
(225)
(62)
1,039

68
66
(52)
—
82

Weighted
average
fair value

$ 21.89
$ 19.44
$ 19.67
—
$ 21.32

At December 31, 2016, the aggregate intrinsic value for the restricted stock and restricted stock units

outstanding was $28.9 million as calculated based on the maximum number of shares of restricted stock and
restricted stock units vesting, using the Company’s quoted closing market price of $25.76 per share on that date.

FORM 10-K Notes to Consolidated Financial Statements

2016 ANNUAL REPORT

F-27

NOTE 8 — STOCK-BASED COMPENSATION — Continued

During the years ended December 31, 2016, 2015 and 2014, the Company recognized approximately $6.6
million, $4.7 million and $3.0 million, respectively, in stock-based compensation expense attributable to restricted
stock and restricted stock units.

At December 31, 2016, the total remaining unrecognized compensation expense related to unvested restricted

stock and restricted stock units was approximately $12.5 million and the weighted average remaining requisite
service period (vesting period) of all non-vested restricted stock and restricted stock units was 1.8 years.

The fair value of restricted stock and restricted stock units vested during 2016, 2015 and 2014 was $4.6 million,

$0.8 million and $0.9 million, respectively.

The total tax beneﬁt recognized for all stock-based compensation was $4.3 million, $3.4 million and $1.9 million

for the years ended December 31, 2016, 2015 and 2014, respectively.

In mid-February 2017, the Company granted awards of 228,174 shares of restricted stock and options to

purchase 590,128 shares of the Company’s common stock at an exercise price of $27.26 per share to certain of its
employees. The fair value of these awards was approximately $12.4 million. All of these awards vest ratably over
three years.

In mid-February 2017, the Company also granted awards of 174,561 shares of restricted stock and options to
purchase 444,491 shares of the Company’s common stock at an exercise price of $26.86 per share to certain of its
employees. The fair value of these awards was approximately $9.3 million. All of these awards vest ratably over
three years.

NOTE 9 — EMPLOYEE BENEFIT PLANS

401(k) Plan

All full-time Company employees are eligible to join the Company’s deﬁned contribution retirement plan the ﬁrst

day of the calendar month immediately following their date of employment. Each employee may contribute up to
the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan
which equals 3% of the employee’s annual compensation, referred to as the Employer’s Safe Harbor Non-Elective
Contribution, which totaled approximately $0.7 million, $0.6 million and $0.4 million in 2016, 2015 and 2014,
respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as
additional contributions. The Company’s discretionary matching contributions totaled $0.9 million, $0.8 million and
$0.5 million in 2016, 2015 and 2014, respectively. The Company made no additional discretionary contributions in
any reporting period presented.

NOTE 10 — EQUITY

Stock Offerings, Retirement and Issuances

On December 9, 2016, the Company completed a public offering of 6,000,000 shares of its common stock. After

deducting offering costs totaling approximately $0.4 million, the Company received net proceeds of approximately
$145.8 million. A portion of the net proceeds of the public offering, along with the proceeds from the Notes Offering
(see Note 6), have been used to partially fund certain acreage acquisitions and midstream asset development,
to repay outstanding borrowings under the Credit Agreement and for general corporate purposes, including capital
expenditures associated with the addition of a fourth drilling rig.

Notes to Consolidated Financial Statements FORM 10-K

F-28

MATADOR RESOURCES COMPANY

NOTE 10 — EQUITY — Continued

On March 11, 2016, the Company completed a public offering of 7,500,000 shares of its common stock. After
deducting offering costs totaling approximately $0.8 million, the Company received net proceeds of approximately
$141.5 million, which were used for general corporate purposes, including to fund a portion of the Company’s 2016
capital expenditures.

As discussed in Note 5, the Company issued 3,300,000 shares of common stock and 150,000 shares of a new
series of Series A Preferred Stock to HEYCO Energy Group, Inc. in connection with the HEYCO Merger. Pursuant to
the statement of resolutions, each share of Series A Preferred Stock would automatically convert into ten shares
of Matador common stock, subject to customary anti-dilution adjustments, upon the vote and approval by Matador’s
shareholders of an amendment to Matador’s Amended and Restated Certiﬁcate of Formation to increase the
number of shares of authorized Matador common stock.

On April 2, 2015, the shareholders of the Company approved an amendment to the Company’s Amended and
Restated Certiﬁcate of Formation that authorized an increase in the number of authorized shares of common stock
from 80,000,000 shares to 120,000,000 shares. Following such approval, the 150,000 outstanding shares of
Series A Preferred Stock converted to 1,500,000 shares of common stock on April 6, 2015. Pursuant to the terms of
the HEYCO Merger, 166,667 of the 1,500,000 shares were being held in escrow at December 31, 2016 to satisfy
certain conditions under the merger agreement.

On April 21, 2015, the Company completed a public offering of 7,000,000 shares of its common stock. After
deducting offering costs totaling approximately $1.2 million, the Company received net proceeds of approximately
$187.6 million.

On May 29, 2014, the Company completed a public offering of 7,500,000 shares of its common stock.
After deducting direct offering costs totaling approximately $0.6 million, the Company received net proceeds of
approximately $181.3 million.

Treasury Stock

On October 27, 2016, October 30, 2015 and October 31, 2014, Matador’s Board of Directors canceled all of the

shares of treasury stock outstanding as of September 30, 2016, September 30, 2015 and September 30, 2014,
respectively. These shares were restored to the status of authorized but unissued shares of common stock of
the Company.

The shares of treasury stock outstanding at December 31, 2016, 2015 and 2014 represent forfeitures of non-
vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements
with employees.

NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS

From time to time, the Company uses derivative ﬁnancial instruments to mitigate its exposure to commodity
price risk associated with oil, natural gas and natural gas liquids prices. The Company records derivative ﬁnancial
instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company
has elected not to apply hedge accounting for its existing derivative ﬁnancial instruments. As a result, the Company
recognizes the change in derivative fair value between reporting periods currently in its consolidated statements
of operations as an unrealized gain or loss. The fair value of the Company’s derivative ﬁnancial instruments is
determined using industry-standard models that consider various inputs including: (i) quoted forward prices for

FORM 10-K Notes to Consolidated Financial Statements

2016 ANNUAL REPORT

F-29

NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments,
as well as other relevant economic measures. The Company has evaluated and considered the credit standings of
its counterparties in determining the fair value of its derivative ﬁnancial instruments.

The Company typically uses costless (or zero-cost) collars and/or swap contracts to manage risks related to

changes in oil, natural gas and natural gas liquids prices. Costless collars provide the Company with downside
price protection through the purchase of a put option which is ﬁnanced through the sale of a call option. Because
the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless”
to the Company. In the case of a costless collar, the put option and the call option have different ﬁxed price
components. In a swap contract, a ﬂoating price is exchanged for a ﬁxed price over a speciﬁed period, providing
downside price protection.

At December 31, 2016, we had entered into various costless collar contracts to mitigate our exposure to

When the settlement price is below the price ﬂoor established by one or more of these collars, the Company
receives from the counterparty an amount equal to the difference between the settlement price and the price ﬂoor
multiplied by the contract oil or natural gas volume. When the settlement price is above the price ceiling
established by one or more of these collars, the Company pays to the counterparty an amount equal to the difference
between the settlement price and the price ceiling multiplied by the contract oil or natural gas volume. When the
settlement price is below the ﬁxed price established by one or more of these swaps, the Company receives from
the counterparty an amount equal to the difference between the settlement price and the ﬁxed price multiplied
by the contract natural gas liquids volume. When the settlement price is above the ﬁxed price established by one or
more of these swaps, the Company pays to the counterparty an amount equal to the difference between the
settlement price and the ﬁxed price multiplied by the contract natural gas liquids volume

At December 31, 2016, the Company had various costless collar contracts open and in place to mitigate its

exposure to oil and natural gas price volatility, each with a speciﬁc term (calculation period), notional quantity
(volume hedged) and price ﬂoor and ceiling. Each contract is set to expire at varying times during 2017 and 2018.

The following is a summary of the Company’s open costless collar contracts for oil and natural gas at

December 31, 2016.

Commodity

Oil
Oil
Natural Gas

Total open derivative
ﬁnancial instruments

Calculation Period

Notional
Quantity
(Bbl or MMBtu)

Weighted
Average
Price Floor
($/Bbl or $/MMBtu)

Weighted
Average
Price Ceiling
($/Bbl or $/MMBtu)

01/01/2017 - 12/31/2017
01/01/2018 - 12/31/2018
01/01/2017 - 12/31/2017

2,760,000
720,000
16,860,000

$ 41.39
$ 43.75
$ 2.40

$ 51.88
$ 63.90
$ 3.59

Fair Value
VV
of Liabilities
(thousands)

$ (18,316)
(751)
(5,887)

$ (24,954)

Notes to Consolidated Financial Statements FORM 10-K

F-30

MATADOR RESOURCES COMPANY

NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

Subsequent to December 31, 2016, the Company entered into various costless collar contracts for oil. The

costless collar contracts for oil included approximately 1,890,000 Bbl in 2017 with a weighted average ﬂoor price of
$50.00 per Bbl and a weighted average ceiling price of $60.75 per Bbl.

From time-to-time we enter into derivative ﬁnancial instruments with certain counterparties. These derivative

ﬁnancial instruments are subject to master netting arrangements; all but one counterparty allow for cross-
commodity master netting provided the settlements dates for the commodities are the same. The Company
does not present different types of commodities with the same counterparty on a net basis in its consolidated
balance sheets.

The following table presents the gross asset and liability fair values of the Company’s commodity price derivative

ﬁnancial instruments and the location of these balances in the consolidated balance sheets as of December 31,
2016 and December 31, 2015 (in thousands).

Derivative Instruments

December 31, 2016
Current liabilities
Other liabilities

Total

December 31, 2015
Current assets
Current liabilities

Total

Gross amounts
recognized

Gross amounts
netted in the
consolidated
balance sheets

Net amounts
presented in
the consolidated
balance sheets

$ (24,203)
(751)
$ (24,954)

$ 16,767

(483)

$ 16,284

$ —
—
$ —

$(483)
483
$ —

$ (24,203)
(751)
$ (24,954)

$ 16,284
—
$ 16,284

The following table summarizes the location and aggregate fair value of all derivative ﬁnancial instruments
recorded in the consolidated statements of operations for the periods presented (in thousands). These derivative
ﬁnancial instruments are not designated as hedging instruments.

Type of Instrument

Location in Statement of Operations

2016

2015

2014

Year Ended December 31,

Derivative Instrument

Oil
Natural Gas
Natural Gas Liquids (NGL)

Realized gain on derivatives

Revenues: Realized gain on derivatives
Revenues: Realized gain (loss) on derivatives
Revenues: Realized gain on derivatives

Oil
Natural Gas
Natural Gas Liquids (NGL)
Unrealized (loss) gain on derivatives

Revenues: Unrealized (loss) gain on derivatives
Revenues: Unrealized (loss) gain on derivatives
Revenues: Unrealized (loss) gain on derivatives

Total

$ 5,851
3,435
—
9,286
(18,969)
(22,269)
—
(41,238)

$ 62,259
12,653
2,182
77,094
(31,897)
(5,440)
(1,928)
(39,265)

$ (31,952) $ 37,829

$ 5,221
(718)
519
5,022
47,178
9,087
2,037
58,302
$63,324

FORM 10-K Notes to Consolidated Financial Statements

2016 ANNUAL REPORT

F-31

NOTE 12 — FAIR VALUE MEASUREMENTS

The Company measures and reports certain ﬁnancial and non-ﬁnancial assets and liabilities on a fair value basis.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction
between market participants at the measurement date (exit price). Fair value measurements are classiﬁed and
disclosed in one of the following categories.

Level 1 Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets.

Level 2 Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for

substantially the full term of the asset or liability. This category includes those derivative instruments that
are valued with industry standard models that consider various inputs including: (i) quoted forward prices
for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying
instruments, as well as other relevant economic measures. Substantially all of these inputs are observable
in the marketplace throughout the full term of the derivative instrument and can be derived from
observable data or supported by observable levels at which transactions are executed in the marketplace.

Level 3 Unobservable inputs that are not corroborated by market data which reﬂect a company’s own market

assumptions.

Financial and non-ﬁnancial assets and liabilities are classiﬁed based on the lowest level of input that is signiﬁcant
to the fair value measurement. The assessment of the signiﬁcance of a particular input to the fair value measurement
requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement
within the fair value hierarchy levels.

At December 31, 2016 and 2015, the carrying values reported on the consolidated balance sheets for accounts

receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, amounts due to afﬁliates,
advances from joint interest owners, amounts due to joint ventures, income taxes payable and other current liabilities
approximate their fair values due to their short-term maturities.

At December 31, 2016 and 2015, the fair value of the Company’s Notes was $605.2 million and $381.0 million,

respectively, based on quoted market prices, which represents Level 1 inputs in the fair value hierarchy.

The following tables summarize the valuation of the Company’s ﬁnancial assets and liabilities that were
accounted for at fair value on a recurring basis in accordance with the classiﬁcations provided above as of
December 31, 2016 and 2015 (in thousands).

Description

Assets (Liabilities)

Oil and natural gas derivatives
Total

Description

Assets (Liabilities)

Oil and natural gas derivatives

Total

Fair Value Measurements at December 31, 2016 using

Level 1

Level 2

Level 3

Total

$ —
$ —

$ (24,954)
$ (24,954)

$ —
$ —

$ (24,954)
$ (24,954)

Fair Value Measurements at December 31, 2015 using

Level 1

Level 2

Level 3

Total

$ —
$ —

$ 16,284
$ 16,284

$ —
$ —

$ 16,284
$ 16,284

Additional disclosures related to derivative ﬁnancial instruments are provided in Note 11. For purposes of fair
value measurement, the Company determined that derivative ﬁnancial instruments (e.g., oil, natural gas and NGL
derivatives) should be classiﬁed as Level 2 in the fair value hierarchy.

Notes to Consolidated Financial Statements FORM 10-K

F-32

MATADOR RESOURCES COMPANY

NOTE 12 — FAIR VALUE MEASUREMENTS — Continued

Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities

acquired in a business combination (see Note 5), lease and well equipment inventory when the market value is
determined to be lower than the cost of the inventory and other property and equipment that are reduced to fair
value when they are impaired or held for sale. The Company recorded no impairment to its lease and well equipment
inventory or other property and equipment in 2016 and 2015. The Company determined the value of the lease and
well equipment inventory using Level 3 inputs and assumptions.

NOTE 13 — COMMITMENTS AND CONTINGENCIES

Ofﬁce Lease

The Company’s corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas,

Texas 75240. The lease for the Company’s corporate headquarters expires during 2026. The base rate escalates
during the course of the lease; however, the Company recognizes rent expense ratably over the term of the lease.

From time to time, the Company also enters into leases for ﬁeld ofﬁces in locations where it has active ﬁeld
operations. These leases are typically for terms of less than ﬁve years and are not considered principal properties.

The following is a schedule of future minimum lease payments required under all ofﬁce lease agreements as of

December 31, 2016 (in thousands).

Year Ending December 31,

2017
2018
2019
2020
2021

Thereafter
Total

Amount

$ 2,443
2,495
2,528
2,602
2,660
12,335
$ 25,063

Rent expense, including fees for operating expenses and consumption of electricity, was $2.9 million, $1.7 million,

and $0.9 million for 2016, 2015 and 2014, respectively.

Natural Gas and NGL Processing and Transportation Commitments

Eagle Ford

Effective September 1, 2012, the Company entered into a ﬁrm ﬁve-year natural gas processing and transportation

agreement whereby the Company committed to transport the anticipated natural gas production from a signiﬁcant
portion of its Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s
facilities. The agreement also includes ﬁrm transportation of the natural gas liquids extracted at the counterparty’s
processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the
counterparty at the tailgate of its processing plant and further transported under its natural gas transportation
agreements. The arrangement contains ﬁxed processing and liquids transportation and fractionation fees, and the
revenue the Company receives varies with the quality of natural gas transported to the processing facilities and
the contract period.

Under this agreement, if the Company does not meet 80% of the maximum thermal quantity transportation and

processing commitments in a contract year, it will be required to pay a deﬁciency fee per MMBtu of natural gas
deﬁciency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the
next contract year for purposes of calculating the natural gas deﬁciency. During certain prior periods, the Company

FORM 10-K Notes to Consolidated Financial Statements

2016 ANNUAL REPORT

F-33

NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued

had an immaterial natural gas deﬁciency, and the counterparty to this agreement waived the deﬁciency fee. The
Company paid approximately $3.0 million and $5.5 million in processing and transportation fees under this agreement
during the years ended December 31, 2016 and 2015, respectively. The future undiscounted minimum payment
under this agreement as of December 31, 2016 is $1.2 million in 2017.

Delaware Basin

As part of the sale of the Loving County Processing System (see Note 5), the Company entered into a 15-year
ﬁxed-fee natural gas gathering and processing agreement whereby the Company committed to deliver the anticipated
natural gas production from a signiﬁcant portion of its Loving County, Texas acreage in West Texas through the
counterparty’s gathering system for processing at the counterparty’s facilities. Under this agreement, if the Company
does not meet the volume commitment for transportation and processing at the facilities in a contract year, it
will be required to pay a deﬁciency fee per MMBtu of natural gas deﬁciency. At the end of each year of the
agreement, the Company can elect to have the previous year’s actual transportation and processing volumes be
the new minimum commitment for each of the remaining years of the contract. As such, the Company has the
ability to unilaterally reduce the gathering and processing commitment if the Company’s production in the Loving
County area is less than the Company’s currently projected production. If the Company ceased operations in this
area at December 31, 2016, the total deﬁciency fee required to be paid would be approximately $11.7 million.
In addition, if the Company elects to reduce the gathering and processing commitment in any year, the Company
has the ability to elect to increase the committed volumes in any future year to the originally agreed gathering
and processing commitment. Any quantity in excess of the volume commitment delivered in a contract year can be
carried over to the next contract year for purposes of calculating the natural gas deﬁciency. The Company paid
approximately $9.8 million and $1.8 million in processing and gathering fees under this agreement during the years
ended December 31, 2016 and 2015, respectively. The Company can elect to either sell the residue gas to the
counterparty at the tailgate of its processing plants or have the counterparty deliver to the Company the residue gas
in-kind to be sold to third parties downstream of the plants.

Other Commitments

The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties

for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s
commitment for the drilling services to be provided, which have typically been for two years or less. The Company
would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor
were unable to secure replacement work for the contracted drilling rigs or if the drilling contractor were unable to
secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company
prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate
termination obligations under its drilling rig contracts were approximately $46.3 million at December 31, 2016.

At December 31, 2016, the Company had outstanding commitments to participate in the drilling and completion

of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s
minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately
$11.1 million at December 31, 2016. The Company expects these costs to be incurred within the next year.

Legal Proceedings

The Company is a party to several lawsuits encountered in the ordinary course of its business. While the ultimate

outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote
that these lawsuits will have a material adverse impact on the Company’s ﬁnancial condition, results of operations or
cash ﬂows.

Notes to Consolidated Financial Statements FORM 10-K

F-34

MATADOR RESOURCES COMPANY

NOTE 14 — SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at December 31, 2016 and 2015

(in thousands).

Accrued evaluated and unproved and unevaluated property costs
Accrued support equipment and facilities costs
Accrued lease operating expenses
Accrued interest on debt
Accrued asset retirement obligations
Accrued partners’ share of joint interest charges
Other

Total accrued liabilities

Supplemental Cash Flow Information

December 31,

2016

2015

$ 54,273
15,139
16,009
6,541
915
5,572
3,011
$ 101,460

$54,586
17,393
7,743
5,806
254
4,565
2,022
$92,369

The following table provides supplemental disclosures of cash ﬂow information for the years ended December 31,

2016, 2015 and 2014 (in thousands).

Cash paid for income taxes
Cash paid for interest expense, net of amounts capitalized
Increase in asset retirement obligations related to mineral properties
Increase in asset retirement obligations related to support equipment

and facilities

Increase (decrease) in liabilities for oil and natural gas properties

capital expenditures

(Decrease) increase in liabilities for support equipment and facilities
Issuance of restricted stock units for Board and advisor services
Stock-based compensation expense recognized as liability
Increase in liabilities for accrued cost to issue equity
Transfer of inventory to oil and natural gas properties

NOTE 15 — SUBSIDIARY GUARANTORS

Year Ended December 31,

2016

2015

2014

$ 2,895
27,464
3,817

506
16,154
2,510

94
5,269
3,843

222

383

120

1,775
(588)
992
569
343
395

(30,683)
12,076
584
79
—
615

32,972
4,290
444
223
—
216

Matador ﬁled a registration statement on Form S-3 with the SEC in 2013, which became effective on May 9, 2013,

and a registration statement on Form S-3 with the SEC in 2014, which became effective upon ﬁling on May 22,
2014, registering, in each case, among other securities, senior and subordinated debt securities and guarantees of
debt securities by certain subsidiaries of Matador (the “Shelf Guarantor Subsidiaries”). On April 14, 2015, the
Company issued the Original Notes and on December 9, 2016, the Company issued the Additional Notes (see Note 6),
which are jointly and severally guaranteed by certain subsidiaries of Matador (the “Notes Guarantor Subsidiaries”
and, together with the Shelf Guarantor Subsidiaries, the “Guarantor Subsidiaries”) on a full and unconditional basis
(except for customary release provisions). At December 31, 2016, the Guarantor Subsidiaries were 100% owned by
Matador, and any subsidiaries of Matador other than the Guarantor Subsidiaries were minor. Matador is a parent
holding company and has no independent assets or operations, and there are no signiﬁcant restrictions on the ability
of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan.

FORM 10-K Notes to Consolidated Financial Statements

2016 ANNUAL REPORT

F-35

NOTE 16 — RELATED PARTY TRANSACTIONS

In June 2015, the Company entered into two joint ventures to develop certain leasehold interests held by certain

afﬁliates (the “HEYCO Afﬁliates”) of HEYCO Energy Group, Inc., the former parent company of HEYCO. The
HEYCO Afﬁliates are owned by George M. Yates, who is a member of the Company’s Board of Directors, and certain
of his afﬁliates. Pursuant to the terms of the transaction, the HEYCO Afﬁliates contributed an aggregate of
approximately 1,900 net acres, primarily in the same properties previously held by HEYCO, to the two newly-formed
entities in exchange for a 50% interest in each entity. The Company has agreed to contribute an aggregate of
approximately $14 million in exchange for the other 50% interest in both entities. As of December 31, 2016, the
Company had contributed an aggregate of approximately $2.1 million to the two entities. The Company’s
contributions will be used to fund future capital expenditures associated with the interests being acquired as well
as to fund acquisitions of other non-operated acreage opportunities.

NOTE 17 — SEGMENT INFORMATION

The Company operates in two business segments: (i) exploration and production and (ii) midstream. The

exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas
properties and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring
plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford
shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas.
During the third quarter of 2016, our midstream business became a reportable segment under U.S. GAAP. The
midstream segment conducts midstream operations in support of the Company’s exploration, development and
production operations and provides natural gas processing, natural gas, oil and salt water gathering services and
salt water disposal services to third parties on a limited basis.

The following tables present selected ﬁnancial information for the periods presented regarding the Company’s

operating segments on a stand-alone basis, expenses that are not allocated to a segment and the consolidation
and elimination entries necessary to arrive at the ﬁnancial information for the Company on a consolidated basis (in
thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from
midstream operations related to third parties, including working interest owners in the Company’s operated wells.
All midstream services revenues associated with Company-owned production are eliminated in consolidation. In
evaluating the operating results of the exploration and production and midstream segments, the Company does not
allocate certain expenses to the individual segments, including general and administrative expenses.

Exploration and
Production

Midstream

Corporate

Eliminations

Year Ended December 31, 2016
Oil and natural gas revenues

Realized gain on derivatives
Unrealized gain on derivatives
Expenses (1)
Operating (loss) income (2)

$ 289,512
—
9,286
(41,238)
391,098
$ (133,538)

$ 1,644
18,982
—
—
8,254
$ 12,372

—
—
—
—
56,001
$ (56,001)

—
(13,764)
—
—
(13,764)
—

$ 1,098,525

$ 140,459

$ 225,681

$ 379,881

$ 67,566

$ 6,913

—

Consolidated
Company

$ 291,156
5,218
9,286
(41,238)
441,589
$ (177,167)

$ 1,464,665

$ 454,360

Expenses include depreciation, depletion and amortization expenses of $118.4 million, $2.7 million and $0.9 million for the exploration and
production, midstream and corporate segments, respectively, and full-cost ceiling impairment expense of $158.6 million for the exploration
and production segment.

(2) Includes $0.4 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

Notes to Consolidated Financial Statements FORM 10-K

F-36

MATADOR RESOURCES COMPANY

NOTE 17 — SEGMENT INFORMATION — Continued

Year Ended December 31, 2015
Oil and natural gas revenues
Midstream services revenues
Realized gain on derivatives
Unrealized loss on derivatives
Expenses (1)
Operating (loss) income (2)

Total Assets

Capital Expenditures (3)

Exploration and
Production

Midstream

Corporate

Eliminations

$ 277,844
—
77,094
(39,265)
1,078,534
$ (762,861)

496
11,485
—
—
5,178
$ 6,803

—
—
—
—
50,604
$(50,604)

$ —

(9,621)
—
—
(9,621)

$ —

Consolidated
Company

$ 278,340
1,864
77,094
(39,265)
1,124,695
$ (806,662)

$1,000,075

$75,980

$ 64,806

$ —

$1,140,861

$ 622,642

$75,009

786

$ —

$ 698,437

(1) Expenses include depreciation, depletion and amortization expenses of $176.7 million, $1.6 million and $0.5 million for the exploration and

production, midstream and corporate segments, respectively, and full-cost ceiling impairment expense of $801.2 million for the exploration
and production segment.

(2) Includes $0.3 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(3) In October 2015, the Company sold the Wolf Processing Plant to EnLink and the cost basis of $31.0 million for those assets was removed from

the total midstream assets.

Year Ended December 31, 2014
Oil and natural gas revenues
Midstream services revenues
Realized gain on derivatives
Unrealized loss on derivatives
Expenses (1)
Operating (loss) income (2)

Total Assets

Capital Expenditures

Exploration and
Production

Midstream

Corporate

Eliminations

$ 366,191
—
5,022
58,302
220,374
$ 209,141

$ 1,521
4,929
—
—
2,703
$ 3,747

—
—
—
—
32,557
$ (32,557)

$1,388,261

$ 35,100

$ 11,129

$ 597,351

$ 12,504

517

—

(3,716)
—
—
(3,716)

—

Consolidated
Company

$ 367,712
1,213
5,022
58,302
251,918
$ 180,331

$1,434,490

$ 610,372

(1) Expenses include depreciation, depletion and amortization expenses of $133.1 million, $1.2 million and $0.4 million for the exploration and

production, midstream and corporate segments, respectively.

(2) Includes $17,000 in net loss attributable to non-controlling interest in subsidiaries related to the midstream segment.

NOTE 18 — SUBSEQUENT EVENTS

Subsequent to December 31, 2016, the Company acquired approximately 13,900 gross (8,200 net) leased and

mineral acres and approximately 1,000 BOE per day of related production from various lessors and other
operators, mostly in and around its existing acreage in the Delaware Basin. The cost of these acquisitions was
approximately $111 million.

On February 17, 2017, the Company contributed substantially all of its midstream assets located in the Rustler

Breaks and Wolf asset areas to San Mateo Midstream, LLC (“San Mateo” or the “Joint Venture”), a joint venture
with a subsidiary of Five Point Capital Partners LLC (“Five Point”). The midstream assets contributed to San Mateo
include (i) the Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (“Black River
Processing Plant”); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler
Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the
Wolf asset area; and (iv) substantially all related oil, natural gas and water gathering systems and pipelines in both
the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). The Company will
continue to operate the Delaware Midstream Assets. The Company retained its ownership in certain midstream
assets owned in South Texas and Northwest Louisiana, which are not part of the Joint Venture.

FORM 10-K Notes to Consolidated Financial Statements

2016 ANNUAL REPORT

F-37

NOTE 18 — SUBSEQUENT EVENTS — Continued

The Company and Five Point own 51% and 49% of the Joint Venture, respectively. Five Point provided initial cash

consideration of $176.4 million to the Joint Venture in exchange for its 49% interest. Approximately $171.5 million
of this cash contribution by Five Point was distributed by the Joint Venture to the Company as a special distribution.
The Company may earn an additional $73.5 million in performance incentives over the next ﬁve years. The
Company contributed the Delaware Midstream Assets and $5.1 million in cash to the Joint Venture in exchange for
its 51% interest. The parties to the Joint Venture have also committed to spend up to an additional $140 million in
the aggregate to expand the Joint Venture’s midstream operations and asset base.

In connection with the Joint Venture, the Company dedicated its current and future leasehold interests
in the Rustler Breaks and Wolf asset areas pursuant to 15-year, ﬁxed-fee natural gas, oil and salt water gathering
agreements and salt water disposal agreements, effective as of February 1, 2017. In addition, the Company
dedicated its current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15-year, ﬁxed fee
natural gas processing agreement (when combined with the gathering and salt water disposal agreements,
the “Operational Agreements”). The Joint Venture will provide the Company with ﬁrm service under each of the
Operational Agreements in exchange for certain minimum volume commitments. The minimum contractual
obligation under the Operational Agreements at inception was approximately $273.5 million.

The following unaudited pro forma consolidated ﬁnancial information is presented to illustrate the effect on the

historical operating results and ﬁnancial position of the Company of (a) the formation of San Mateo and the
transactions associated with the Joint Venture and (b) the Company’s acquisition on February 14, 2017 of the
remaining non-controlling interest in Fulcrum Delaware Water Resources, LLC (“Fulcrum Delaware Water Resources”)
not previously owned by the Company for approximately $2.6 million (collectively, the “Transactions”).

The Unaudited Pro Forma Consolidated Statement of Operations for the year ended December 31, 2016, if
presented, would contain an adjustment of $4.5 million to increase the net income attributable to non-controlling
interest in subsidiaries from $0.4 million to $4.9 million, which would increase the net loss attributable to
Matador Resources Company shareholders from $97.4 million to $102.0 million, and an adjustment of $0.05 per
diluted common share to increase the net loss per diluted common share attributable to Matador Resources
Company shareholders from $1.07 to $1.12.

The following Unaudited Pro Forma Consolidated Balance Sheet as of December 31, 2016, presented for
illustrative purposes, is based on the historical ﬁnancial statements of the Company as of December 31, 2016,
after giving effect to the Transactions as if they had occurred on December 31, 2016.

Notes to Consolidated Financial Statements FORM 10-K

F-38

MATADOR RESOURCES COMPANY

NOTE 18 — SUBSEQUENT EVENTS — Continued

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET

December 31, 2016

As Reported

Adjustment

Pro Forma

ASSETS
Current assets

Cash
Restricted cash
Accounts receivable
Oil and natural gas revenues
Joint interest billings
Other
Lease and well equipment inventory
Prepaid expenses and other assets

Total current assets
Property and equipment, at cost

Oil and natural gas properties, full-cost method
Evaluated
Unproved and unevaluated
Other property and equipment
Less accumulated depletion, depreciation and amortization

Net property and equipment

Other assets

Total assets

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities

Accounts payable
Accrued liabilities
Royalties payable
Amounts due to afﬁliates
Derivative instruments
Advances from joint interest owners
Amounts due to joint ventures
Other current liabilities

Total current liabilities

Long-term liabilities

Senior unsecured notes payable
Asset retirement obligations
Derivative instruments
Amounts due to joint ventures
Other long-term liabilities

Total long-term liabilities

Commitments and contingencies (Note 13)
Shareholders’ equity

$ 212,884
1,258

34,154
19,347
5,167
3,045
3,327
279,182

9,407 (2)

$ 164,340 (1) $ 377,224
10,665
—
34,154
19,347
5,167
3,045
3,327
452,929

—
—
—
—
—
173,747

2,408,305
479,736
160,795
(1,864,311)
1,184,525
958
$ 1,464,665

—
—
—
—
—
—
$ 173,747

2,408,305
479,736
160,795
(1,864,311)
1,184,525
958
$ 1,638,412

4,674
101,460
23,988
8,651
24,203
1,700
4,251
578
169,505

573,924
19,725
751
1,771
7,544
603,715

—
—
—
—
—
—
—
—
—

—
—
—
—
—
—

4,674
101,460
23,988
8,651
24,203
1,700
4,251
578
169,505

573,924
19,725
751
1,771
7,544
603,715

Common stock — $0.01 par value, 120,000,000 shares authorized;
99,518,764 and 85,567,021 shares issued; and 99,511,931 and
85,564,435 shares outstanding, respectively

Additional paid-in capital
Accumulated deﬁcit

Total Matador Resources Company shareholders’ equity

Non-controlling interest in subsidiaries

Total shareholders’ equity

Total liabilities and shareholders’ equity

995
1,325,481
(636,351)
690,125
1,320
691,445
$ 1,464,665

—

124,871 (3)

—
124,871
48,876 (4)
173,747
$ 173,747

995
1,450,352
(636,351)
814,996
50,196
865,192
$ 1,638,412

FORM 10-K Notes to Consolidated Financial Statements

2016 ANNUAL REPORT

F-39

NOTE 18 — SUBSEQUENT EVENTS — Continued

(1) Represents $176.4 million of cash contributed by Five Point in connection with the formation of San Mateo less (i) approximately $2.6 million

paid by the Company to acquire the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and
(ii) $10.0 million of cash restricted to operations of San Mateo. Also reﬂects $0.6 million released from restriction upon the purchase of the
non-controlling interest in Fulcrum Delaware Water Resources not previously owned by the Company.

(2) Represents $10.0 million in cash contributed to San Mateo less $0.6 million released from restriction upon the purchase of the non-controlling

interest in Fulcrum Delaware Water Resources that the Company did not previously own.

(3) Reﬂects the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the Company did not previously own and the

amount received in connection with the formation of San Mateo.

(4) Represents the adjustment required to reﬂect the purchase of the non-controlling interest in Fulcrum Delaware Water Resources that the

Company did not previously own and Five Point’s 49% non-controlling interest in San Mateo.

Notes to Consolidated Financial Statements FORM 10-K

F-40

MATADOR RESOURCES COMPANY

Unaudited Supplementary Information

MATADOR RESOURCES COMPANY AND SUBSIDIARIES
December 31, 2016, 2015 and 2014

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES

Costs Incurred

The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and
development of oil and natural gas properties for the years ended December 31, 2016, 2015 and 2014 (in thousands).

Property acquisition costs

Proved
Unproved and unevaluated

Exploration costs
Development costs

Total costs incurred (1)

Year Ended December 31,

2016

2015

2014

—
108,206
113,562
158,113
$ 379,881

$ 16,524
253,923
122,495
229,700
$622,642

2,728
78,484
156,178
359,961
$597,351

(1) Excludes midstream-related development and corporate costs of approximately $74.5 million, $75.8 million and $13.0 million for the years

ended December 31, 2016, 2015 and 2014, respectively.

Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas

properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the years
ended December 31, 2016, 2015 and 2014, most of the Company’s property acquisition costs resulted from the
acquisition of unproved and unevaluated leasehold positions.

Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant

further examination and in examining speciﬁc areas that are considered to have prospects of containing oil and
natural gas, including costs of drilling exploratory wells, geological and geophysical costs, and costs of carrying and
retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the
related oil and natural gas properties.

Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting,

treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations
for drilling, drilling and equipping development wells and acquiring, constructing and installing production facilities.

Costs incurred also include new asset retirement obligations established, as well as changes to asset retirement

obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included
in the table above were approximately $4.4 million, $3.3 million and $4.0 million for the years ended December 31,
2016, 2015 and 2014, respectively. Capitalized general and administrative expenses that are directly related to
acquisition, exploration and development activities are also included in the table above. The Company capitalized
$15.7 million, $6.9 million and $6.4 million of these internal costs in 2016, 2015 and 2014, respectively.
Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized
$3.7 million, $3.9 million and $2.8 million of its interest expense for the years ended December 31, 2016, 2015
and 2014, respectively.

FORM 10-K Unaudited Supplementary Information

2016 ANNUAL REPORT

F-41

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

Oil and Natural Gas Reserves

Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate

with reasonable certainty to be recoverable in future years from known reservoirs using existing economic
and operating conditions. Estimating oil and natural gas reserves is complex and inexact because of the numerous
uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical,
petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated
interpretations of that data can vary. The process also requires certain economic assumptions, including, but not
limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses
and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates.

The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry

and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and
Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in
South Texas, the economic value of the natural gas liquids associated with the natural gas is included in the
estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold.
The Company’s oil and natural gas reserves estimates for the years ended December 31, 2016, 2015 and 2014
were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then
audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc.,
independent reservoir engineers.

Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no

provision for price and cost escalations in future periods except by contractual arrangements. The commodity
prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of ﬁrst-day-of-
the-month oil and natural gas prices for the previous 12-month period. For the period from January through
December 2016, these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively.
For the period from January through December 2015, these average oil and natural gas prices were $46.79 per Bbl
and $2.59 per MMBtu, respectively. For the period from January through December 2014, these average oil and
natural gas prices were $91.48 per Bbl and $4.35 per MMBtu, respectively.

The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net

proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to
properties located in the United States. The estimated reserves shown below are for proved reserves only and do
not include any value for unproved reserves classiﬁed as probable or possible reserves that might exist for these
properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond
those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas
is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas.

Unaudited Supplementary Information FORM 10-K

F-42

MATADOR RESOURCES COMPANY

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

Total at December 31, 2013

Revisions of prior estimates
Purchases of minerals in-place
Extensions and discoveries
Production

Total at December 31, 2014

Revisions of prior estimates
Purchases of minerals in-place
Extensions and discoveries
Production

Total at December 31, 2015

Revisions of prior estimates
Extensions and discoveries
Production

Total at December 31, 2016

Proved Developed Reserves
December 31, 2013
December 31, 2014
December 31, 2015
December 31, 2016

Proved Undeveloped Reserves
December 31, 2013
December 31, 2014
December 31, 2015
December 31, 2016

Net Proved Reserves

Oil

(MBbl)

16,362
(1,196)
10
12,328
(3,320)
24,184
(2,609)
1,102
27,459
(4,492)
45,644
(6,440)
22,869
(5,096)
56,977

8,258
14,053
17,129
22,604

8,104
10,131
28,515
34,373

Natural
Gas

(MMcf)

212,195
164
433
69,566
(15,303)
267,055
(75,433)
2,927
70,054
(27,702)
236,901
(28,481)
114,730
(30,501)
292,649

53,458
102,795
101,447
126,759

158,737
164,260
135,454
165,890

Oil
Equivalent

(MBOE)

51,729
(1,169)
82
23,921
(5,870)
68,693
(15,181)
1,589
39,135
(9,109)
85,127
(11,187)
41,992
(10,180)
105,752

17,168
31,185
34,037
43,731

34,561
37,508
51,090
62,021

The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for

the years ended December 31, 2016, 2015 and 2014.

The Company’s proved oil and natural gas reserves increased to 105,752 MBOE at December 31, 2016 from
85,127 MBOE at December 31, 2015. The Company’s proved oil and natural gas reserves increased by 30,805 MBOE
and the Company produced 10,180 MBOE during the year ended December 31, 2016, resulting in a net increase
of 20,625 MBOE. An increase of 41,992 MBOE in proved oil and natural gas reserves was a result of extensions and
discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring
plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas
reserves decreased by 11,187 MBOE during 2016 as a result of the reclassiﬁcation of proved undeveloped reserves
to contingent resources, primarily due to the decline in weighted average commodity prices used to estimate
proved reserves during 2016, as compared to 2015. The Company anticipates that these contingent resources may
be reclassiﬁed to proved undeveloped reserves in future periods should the oil and natural gas prices used to
estimate proved reserves improve from the prices at December 31, 2016. The Company’s proved developed oil and
natural gas reserves increased to 43,731 MBOE at December 31, 2016 from 34,037 MBOE at December 31, 2015,
primarily due to proved developed reserves added as a result of drilling operations in the Wolfcamp and Bone Spring
plays in the Delaware Basin. At December 31, 2016, the Company’s proved reserves were made up of
approximately 54% oil and 46% natural gas and were approximately 41% proved developed and approximately
59% proved undeveloped.

FORM 10-K Unaudited Supplementary Information

2016 ANNUAL REPORT

F-43

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

The Company’s proved oil and natural gas reserves increased to 85,127 MBOE at December 31, 2015 from

68,693 MBOE at December 31, 2014. The Company’s proved oil and natural gas reserves increased by 25,543 MBOE
and the Company produced 9,109 MBOE during the year ended December 31, 2015, resulting in a net increase
of 16,434 MBOE. An increase of 39,135 MBOE in proved oil and natural gas reserves was a result of extensions and
discoveries during the year, which was primarily attributable to drilling operations in the Wolfcamp and Bone Spring
plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company’s proved oil and natural gas
reserves decreased by 15,181 MBOE during the year as a result of revisions to previous estimates, primarily the
removal of 1,935 MBbl of proved undeveloped oil reserves in the Eagle Ford shale play in South Texas in 2015, as
well as the removal of approximately 64.3 Bcf, or 10,716 MBOE, of proved undeveloped natural gas reserves,
primarily in the Haynesville shale in Northwest Louisiana, primarily resulting from the decline in commodity prices
during 2015. The Company also purchased minerals in-place with proved reserves of 1,589 MBOE in 2015, primarily
as part of the HEYCO Merger. The Company’s proved developed oil and natural gas reserves increased to 34,037
MBOE at December 31, 2015 from 31,185 MBOE at December 31, 2014, primarily due to proved developed
reserves added as a result of drilling operations in the Wolfcamp and Bone Spring plays in the Delaware Basin and
the Eagle Ford shale plus the conversion of previously undeveloped natural gas reserves in the Haynesville
shale to proved developed reserves. At December 31, 2015, the Company’s proved reserves were made up of
approximately 54% oil and 46% natural gas and were approximately 40% proved developed and approximately
60% proved undeveloped.

The Company’s proved oil and natural gas reserves increased to 68,693 MBOE at December 31, 2014 from

51,729 MBOE at December 31, 2013. The Company’s proved oil and natural gas reserves increased by 22,834 MBOE
and the Company produced 5,870 MBOE during the year ended December 31, 2014, resulting in a net increase
of 16,964 MBOE. An increase of 23,921 MBOE in proved oil and natural gas reserves was a result of extensions and
discoveries during the year, which was primarily attributable to drilling operations in the Eagle Ford shale play in
South Texas and in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West
Texas, plus additional proved undeveloped natural gas reserves identiﬁed on the Company’s properties in the
Haynesville shale. The Company’s proved oil and natural gas reserves decreased by 1,169 MBOE during the year as
a result of revisions to previous estimates, primarily downward revisions of proved undeveloped oil reserves on
certain of the Company’s undeveloped locations in the Eagle Ford shale play in South Texas in 2014. The Company
also purchased minerals in-place with proved reserves of 82 MBOE in 2014. The Company’s proved developed oil
and natural gas reserves increased to 31,185 MBOE at December 31, 2014 from 17,168 MBOE at December 31,
2013, primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford shale and
in the Wolfcamp and Bone Spring plays in the Delaware Basin plus the conversion of previously undeveloped
natural gas reserves in the Haynesville shale to proved developed reserves. At December 31, 2014, the Company’s
proved reserves were made up of approximately 35% oil and 65% natural gas and were approximately 45% proved
developed and approximately 55% proved undeveloped.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved
Oil and Natural Gas Reserves

The standardized measure of discounted future net cash ﬂows relating to proved oil and natural gas reserves is

not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural
gas properties. An estimate of fair market value would also take into account, among other things, the recovery of
reserves not presently classiﬁed as proved, anticipated future changes in prices and costs, potential improvements
in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different
discount rates.

Unaudited Supplementary Information FORM 10-K

F-44

MATADOR RESOURCES COMPANY

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued

As noted previously, for the period from January through December 2016, the unweighted, arithmetic averages

of ﬁrst-day-of-the-month oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For
the period from January through December 2015, the comparable average oil and natural gas prices were $46.79 per
Bbl and $2.59 per MMBtu, respectively. For the period from January through December 2014, the comparable
average oil and natural gas prices were $91.48 per Bbl and $4.35 per MMBtu, respectively.

Future net cash ﬂows were computed by applying these oil and natural gas prices, adjusted for all associated
transportation and gathering costs, gravity and energy content, and regional price differentials, to year-end quantities
of proved oil and natural gas reserves and accounting for any future production and development costs associated
with producing these reserves; neither prices nor costs were escalated with time in these computations.

Future income taxes were computed by applying the statutory tax rate to the excess of future net cash ﬂows

relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net
operating loss carryforwards available to the Company were also considered in the computation of future income
taxes. Future net cash ﬂows after income taxes were discounted using a 10% annual discount rate to derive the
standardized measure of discounted future net cash ﬂows.

The following table presents the standardized measure of discounted future net cash ﬂows relating to proved oil

and natural gas reserves for the years ended December 31, 2016, 2015 and 2014 (in thousands).

Future cash inﬂows
Future production costs
Future development costs
Future income tax expense
Future net cash ﬂows

10% annual discount for estimated timing of cash ﬂows

$ 2,684,877

$2,461,131

(927,725)
(630,280)
(24,742)
1,102,130
(527,087)

(843,117)
(615,692)
(43,956)
958,366
(429,185)

Standardized measure of discounted future net cash ﬂows

$ 575,043

$ 529,181

$3,197,317
(803,662)
(553,799)
(321,088)
1,518,768
(605,449)
$ 913,319

Year Ended December 31,

2016

2015

2014

The following table summarizes the changes in the standardized measure of discounted future net cash ﬂows
relating to proved oil and natural gas reserves for the years ended December 31, 2016, 2015 and 2014 (in thousands).

Balance, beginning of period
Net change in sales and transfer prices and in production (lifting) costs

related to future production

Changes in estimated future development costs
Sales and transfers of oil and natural gas produced during the period
Purchases of reserves in place
Net change due to extensions and discoveries
Net change due to revisions in estimates of reserves quantities
Previously estimated development costs incurred during the period
Accretion of discount
Other
Net change in income taxes

Standardized measure of discounted future net cash ﬂows

Year Ended December 31,

2016

2015

2014

$ 529,181

$ 913,319

$ 578,668

(92,477)
(74,142)
(191,908)
—
360,033
(95,917)
84,519
51,779
(1,962)
5,937
$ 575,043

(509,901)
(145,861)
(184,612)
16,321
401,895
(285,823)
121,543
82,574
2,029
117,697
$ 529,181

87,067
(150,447)
(283,187)
1,838
537,472
(26,263)
187,459
65,518
5,492
(90,298)
$ 913,319

FORM 10-K Unaudited Supplementary Information

2016 ANNUAL REPORT

F-45

SELECTED QUARTERLY FINANCIAL INFORMATION

The following table presents selected unaudited quarterly ﬁnancial information for 2016 (in thousands, except

per share data).

2016
Oil and natural gas revenues
Third-party midstream services revenues
Realized (loss) gain on derivatives
Unrealized (loss) gain on derivatives
Expenses (1)
Other income (expense) (2)
Income (loss) before income taxes
Income tax provision (beneﬁt)
Net income (loss)
Net (income) loss attributable to non-controlling interest

in subsidiaries

Net income (loss) attributable to

December 31 September 30

June 30

March 31

$ 94,815
2,261
(1,127)
(10,977)
76,753
96,196
104,415
105
104,310

$ 83,079
1,566
885
3,203
71,879
(5,948)
10,906
(1,141)
12,047

$ 69,336
918
2,465
(26,625)
146,705
(5,136)
(105,747)
—
(105,747)

$ 43,926
473
7,063
(6,839)
146,252
(6,038)
(107,667)
—
(107,667)

(155)

(116)

(106)

Matador Resources Company shareholders

$ 104,155

$ 11,931

$ (105,853)

$ (107,654)

Earnings (loss) per common share

Basic

Diluted

1.10

1.09

$ 0.13

(1.15)

(1.26)

(1) Expenses for June 30 and March 31, 2016 included full-cost ceiling impairment charges of $78.2 million, and $80.5 million, respectively.

(2) Other income (expense) for December 31, 2016 included gain on the sale of the Loving County Processing System of $104.1 million. See Note 5.

The following table presents selected unaudited quarterly ﬁnancial information for 2015 (in thousands, except

per share data).

2015
Oil and natural gas revenues
Third-party midstream services revenues
Realized gain on derivatives
Unrealized (loss) gain on derivatives
Expenses (1)
Other expense
Loss before income taxes
Income tax provision (beneﬁt)
Net loss
Net income attributable to non-controlling interest

in subsidiaries

Net loss attributable to

December 31

September 30

June 30

March 31

$ 56,212
480
24,948
(13,909)
290,751
5,599
(228,619)
1,677
(230,296)

$ 71,815
569
19,862
6,733
367,633
6,665
(275,319)
(33,305)
(242,014)

$ 87,848
464
13,780
(23,532)
319,140
5,786
(246,366)
(89,350)
(157,016)

$ 62,465
351
18,504
(8,557)
147,171
2,180
(76,588)
(26,390)
(50,198)

(105)

(45)

(75)

(36)

Matador Resources Company shareholders

$(230,401)

$(242,059)

$(157,091)

$(50,234)

Loss per common share attributable to

Matador Resources Company shareholders
Basic

Diluted

(2.72)

(2.86)

(1.89)

(0.68)

(1) Expenses for December 31, September 30, June 30 and March 31, 2015 included full-cost ceiling impairment charges of $219.4 million,

$285.7 million, $229.0 million and $67.1 million, respectively.

Unaudited Supplementary Information FORM 10-K

MATADOR RESOURCES COMPANY

Exhibit 31.1

CERTIFICATION

I, Joseph Wm. Foran, certify that:

1. I have reviewed this annual report on Form 10-K of Matador Resources Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to

state a material fact necessary to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the ﬁnancial statements, and other ﬁnancial information included in this report, fairly
present in all material respects the ﬁnancial condition, results of operations and cash ﬂows of the registrant as
of, and for, the periods presented in this report;

4. The registrant’s other certifying ofﬁcer(s) and I are responsible for establishing and maintaining disclosure

controls and procedures (as deﬁned in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
ﬁnancial reporting (as deﬁned in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;

b. Designed such internal control over ﬁnancial reporting, or caused such internal control over ﬁnancial

reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
ﬁnancial reporting and the preparation of ﬁnancial statements for external purposes in accordance with
generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this

report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of
the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over ﬁnancial reporting that occurred

during the registrant’s most recent ﬁscal quarter (the registrant’s fourth ﬁscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over ﬁnancial reporting; and

5. The registrant’s other certifying ofﬁcer(s) and I have disclosed, based on our most recent evaluation of internal
control over ﬁnancial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):

a. All signiﬁcant deﬁciencies and material weaknesses in the design or operation of internal control over

ﬁnancial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report ﬁnancial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a signiﬁcant

role in the registrant’s internal control over ﬁnancial reporting.

March 1, 2017

FORM 10-K

/s/ Joseph Wm. Foran
Joseph Wm. Foran
Chairman and Chief Executive Ofﬁcer
(Principal Executive Ofﬁcer)

2016 ANNUAL REPORT

Exhibit 31.2

CERTIFICATION

I, David E. Lancaster, certify that: